High strength alloys

ABSTRACT

High strength metal alloys are described herein. At least one composition of a metal alloy includes chromium, nickel, copper, manganese, silicon, niobium, tungsten and iron. System, methods, and heaters that include the high strength metal alloys are described herein. At least one heater system may include a canister at least partially made from material containing at least one of the metal alloys. At least one system for heating a subterranean formation may include a tublar that is at least partially made from a material containing at least one of the metal alloys.

PRIORITY CLAIM

This patent application is a divisional of U.S. patent application Ser.No. 11/788,858 entitled “HIGH STRENGTH ALLOYS” which claims priorityU.S. Provisional Patent No. 60/794,298 entitled “SYSTEMS AND PROCESSESFOR USE IN TREATING SUBSURFACE FORMATIONS” to Vinegar et al. filed onApr. 21, 2006, which is incorporated by reference in its entirety; andto U.S. Provisional Patent No. 60/853,096 entitled “SYSTEMS, METHODS,AND PROCESSES FOR USE IN TREATING SUBSURFACE FORMATIONS” to Vinegar etal. filed on Oct. 20, 2006, which is incorporated by reference in itsentirety.

RELATED PATENTS

This patent application incorporates by reference in its entirety eachof U.S. Pat. Nos. 6,688,387 to Wellington et al.; 6,991,036 toSumnu-Dindoruk et al.; 6,698,515 to Karanikas et al.; 6,880,633 toWellington et al.; 6,782,947 to de Rouffignac et al; 6,991,045 toVinegar et al.; 7,073,578 to Vinegar et al.; 7,121,342 to Vinegar etal.; and 7,559,367 to Vinegar et al. This patent applicationincorporates by reference in its entirety U.S. Patent ApplicationPublication Nos. 2005-0269313 to Vinegar et al.; and 2007-0133960 toVinegar et al.

GOVERNMENT INTEREST

The Government has certain rights in this invention pursuant toAgreement No. ERD-05-2516 between UT-Battelle, LLC, operating underprime contract No. DE-ACO5-00OR22725 for the US Department of Energy andShell Exploration and Production Company.

The Government has certain rights in the invention pursuant to AgreementNo. SD 10634 between Sandia National Laboratories and Shell Explorationand Production Company.

BACKGROUND

1. Field of the Invention

The present invention relates generally to methods and systems forproduction of hydrocarbons, hydrogen, and/or other products from varioussubsurface formations such as hydrocarbon containing formations.

2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used asenergy resources, as feedstocks, and as consumer products. Concerns overdepletion of available hydrocarbon resources and concerns over decliningoverall quality of produced hydrocarbons have led to development ofprocesses for more efficient recovery, processing and/or use ofavailable hydrocarbon resources. In situ processes may be used to removehydrocarbon materials from subterranean formations. Chemical and/orphysical properties of hydrocarbon material in a subterranean formationmay need to be changed to allow hydrocarbon material to be more easilyremoved from the subterranean formation. The chemical and physicalchanges may include in situ reactions that produce removable fluids,composition changes, solubility changes, density changes, phase changes,and/or viscosity changes of the hydrocarbon material in the formation. Afluid may be, but is not limited to, a gas, a liquid, an emulsion, aslurry, and/or a stream of solid particles that has flow characteristicssimilar to liquid flow.

A wellbore may be formed in a formation. In some embodiments wellboresmay be formed using reverse circulation drilling methods. Reversecirculation methods are suggested, for example, in published U.S. PatentApplication Publication No. 2004-0079553 to Livingstone, and U.S. Pat.Nos. 6,854,534 to Livingstone; 6,892,829 to Livingstone, 7,090,018 toLivingstone; and 4,823,890 to Lang, the disclosures of which areincorporated herein by reference. Reverse circulation methods generallyinvolve circulating a drilling fluid to a drilling bit through anannulus between concentric tubulars to the borehole in the vicinity ofthe drill bit, and then through openings in the drill bit and to thesurface through the center of the concentric tubulars, with cuttingsfrom the drilling being carried to the surface with the drilling fluidrising through the center tubular. A wiper or shroud may be providedabove the drill bit and above a point where the drilling fluid exits theannulus to prevent the drilling fluid from mixing with formation fluids.The drilling fluids may be, but is not limited to, air, water, brinesand/or conventional drilling fluids.

In some embodiments, a casing or other pipe system may be placed orformed in a wellbore. U.S. Pat. No. 4,572,299 issued to Van Egmond etal., which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. In some embodiments,components of a piping system may be welded together. Quality of formedwells may be monitored by various techniques. In some embodiments,quality of welds may be inspected by a hybrid electromagnetic acoustictransmission technique known as EMAT. EMAT is described in U.S. Pat.Nos. 5,652,389 to Schaps et al.; 5,760,307 to Latimer et al.; 5,777,229to Geier et al.; and 6,155,117 to Stevens et al., each of which isincorporated by reference as if fully set forth herein.

In some embodiments, an expandable tubular may be used in a wellbore.Expandable tubulars are described in U.S. Pat. Nos. 5,366,012 toLohbeck, and 6,354,373 to Vercaemer et al., each of which isincorporated by reference as if fully set forth herein.

Heaters may be placed in wellbores to heat a formation during an in situprocess. Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom; 2,732,195 toLjungstrom; 2,780,450 to Ljungstrom; 2,789,805 to Ljungstrom; 2,923,535to Ljungstrom; and 4,886,118 to Van Meurs et al.; each of which isincorporated by reference as if fully set forth herein.

Application of heat to oil shale formations is described in U.S. Pat.Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heat maybe applied to the oil shale formation to pyrolyze kerogen in the oilshale formation. The heat may also fracture the formation to increasepermeability of the formation. The increased permeability may allowformation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

A heat source may be used to heat a subterranean formation. Electricheaters may be used to heat the subterranean formation by radiationand/or conduction. An electric heater may resistively heat an element.U.S. Pat. No. 2,548,360 to Germain, which is incorporated by referenceas if fully set forth herein, describes an electric heating elementplaced in a viscous oil in a wellbore. The heater element heats andthins the oil to allow the oil to be pumped from the wellbore. U.S. Pat.No. 4,716,960 to Eastlund et al., which is incorporated by reference asif fully set forth herein, describes electrically heating tubing of apetroleum well by passing a relatively low voltage current through thetubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to VanEgmond, which is incorporated by reference as if fully set forth herein,describes an electric heating element that is cemented into a wellborehole without a casing surrounding the heating element.

U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated byreference as if fully set forth herein, describes an electric heatingelement that is positioned in a casing. The heating element generatesradiant energy that heats the casing. A granular solid fill material maybe placed between the casing and the formation. The casing mayconductively heat the fill material, which in turn conductively heatsthe formation.

U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated byreference as if fully set forth herein, describes an electric heatingelement. The heating element has an electrically conductive core, asurrounding layer of insulating material, and a surrounding metallicsheath. The conductive core may have a relatively low resistance at hightemperatures. The insulating material may have electrical resistance,compressive strength, and heat conductivity properties that arerelatively high at high temperatures. The insulating layer may inhibitarcing from the core to the metallic sheath. The metallic sheath mayhave tensile strength and creep resistance properties that arerelatively high at high temperatures.

U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

Obtaining permeability in an oil shale formation between injection andproduction wells tends to be difficult because oil shale is oftensubstantially impermeable. Many methods have attempted to link injectionand production wells. These methods include: hydraulic fracturing suchas methods investigated by Dow Chemical and Laramie Energy ResearchCenter; electrical fracturing by methods investigated by Laramie EnergyResearch Center; acid leaching of limestone cavities by methodsinvestigated by Dow Chemical; steam injection into permeable nahcolitezones to dissolve the nahcolite by methods investigated by Shell Oil andEquity Oil; fracturing with chemical explosives by methods investigatedby Talley Energy Systems; fracturing with nuclear explosives by methodsinvestigated by Project Bronco; and combinations of these methods. Manyof these methods, however, have relatively high operating costs and lacksufficient injection capacity.

Large deposits of heavy hydrocarbons (heavy oil and/or tar) contained inrelatively permeable formations (for example in tar sands) are found inNorth America, South America, Africa, and Asia. Tar can be surface-minedand upgraded to lighter hydrocarbons such as crude oil, naphtha,kerosene, and/or gas oil. Surface milling processes may further separatethe bitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

In situ production of hydrocarbons from tar sand may be accomplished byheating and/or injecting a gas into the formation. U.S. Pat. Nos.5,211,230 to Ostapovich et al. and 5,339,897 to Leaute, which areincorporated by reference as if fully set forth herein, describe ahorizontal production well located in an oil-bearing reservoir. Avertical conduit may be used to inject an oxidant gas into the reservoirfor in situ combustion.

U.S. Pat. No. 2,780,450 to Ljungstrom describes heating bituminousgeological formations in situ to convert or crack a liquid tar-likesubstance into oils and gases.

U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated byreference as if fully set forth herein, describes contacting oil, heat,and hydrogen simultaneously in a reservoir. Hydrogenation may enhancerecovery of oil from the reservoir.

U.S. Pat. No. 5,046,559 to Glandt and U.S. Pat. No. 5,060,726 to Glandtet al., which are incorporated by reference as if fully set forthherein, describe preheating a portion of a tar sand formation between aninjector well and a producer well. Steam may be injected from theinjector well into the formation to produce hydrocarbons at the producerwell.

As outlined above, there has been a significant amount of effort todevelop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from hydrocarbon containing formations.At present, however, there are still many hydrocarbon containingformations from which hydrocarbons, hydrogen, and/or other productscannot be economically produced. Thus, there is still a need forimproved methods and systems for production of hydrocarbons, hydrogen,and/or other products from various hydrocarbon containing formations.

SUMMARY

Embodiments described herein generally relate to one or more metalcompositions. In some embodiments, systems and methods using materialscontaining the metal compositions are described.

In some embodiments a metal alloy composition may include from 18percent to 22 percent by weight chromium; from 5 percent to 13 percentby weight nickel; between 3 percent and 10 percent by weight copper;from 1 percent to 10 percent by weight manganese; from 0.3 percent to 1percent by weight silicon; from 0.5 percent to 1.5 percent by weightniobium; from 0.5 to 2 percent by weight tungsten; and from 38 percentto 63 percent by weight iron.

In some embodiments, a metal alloy composition may include from 18percent to 22 percent by weight chromium; from 5 percent to 9 percent byweight nickel; from 1 percent to 6 percent by weight copper; from 0.5percent to 1.5 percent by weight niobium; from 1 to 10 percent by weightmanganese; from 0.5 to 1.5 percent by weight of tungsten; from 36percent to 74 percent by weight iron; and precipitates of nanonitrides,wherein the ratio of tungsten to copper is between about 1/10 and 10/1.

In some embodiments, the invention describes a heater system may includea heat generating element and a canister surrounding the heat generatingelement least partially made from material containing: from 18 percentto 22 percent by weight chromium; from 5 percent to 14 percent by weightnickel; from 1 percent to 10 percent by weight copper; from 0.5 percentto 1.5 percent by weight niobium; from 36 percent to 70.5 percent byweight iron; and precipitates of nanonitrides.

In some embodiments, the invention describes a system for heating asubterranean formation comprising a tubular, the tubular at leastpartially made from a material containing: from 18 percent to 22 percentby weight chromium; from 10 percent to 14 percent by weight nickel; from1 percent to 10 percent by weight copper; from 0.5 percent to 1.5percent by weight niobium; from 36 percent to 70.5 percent by weightiron; and precipitates of nanonitrides.

In further embodiments, features from specific embodiments may becombined with features from other embodiments. For example, featuresfrom one embodiment may be combined with features from any of the otherembodiments.

In further embodiments, treating a subsurface formation is performedusing any of the methods, systems, or heaters described herein.

In further embodiments, additional features may be added to the specificembodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention may become apparent to those skilledin the art with the benefit of the following detailed description andupon reference to the accompanying drawings in which:

FIG. 1 depicts an illustration of stages of heating a hydrocarboncontaining formation.

FIG. 2 shows a schematic view of an embodiment of a portion of an insitu heat treatment system for treating a hydrocarbon containingformation.

FIG. 3 depicts a schematic of an embodiment of a Kalina cycle forproducing electricity.

FIG. 4 depicts a schematic of an embodiment of a Kalina cycle forproducing electricity.

FIG. 5 depicts a schematic representation of an embodiment of a systemfor treating the mixture produced from an in situ heat treatmentprocess.

FIG. 5A depicts a schematic representation of an embodiment of a systemfor treating a liquid stream produced from an in situ heat treatmentprocess.

FIG. 6 depicts a schematic representation of another embodiment of asystem for treating a liquid stream produced from an in situ heattreatment process.

FIG. 7 depicts a schematic representation of an embodiment of a systemfor treating a liquid stream produced from an in situ heat treatmentprocess.

FIG. 8 depicts a schematic representation of an embodiment of a systemfor forming and transporting tubing to a treatment area.

FIG. 9A depicts an embodiment of a drilling string including cuttingstructures positioned along the drilling string.

FIG. 9B depicts an embodiment of a drilling string including cuttingstructures positioned along the drilling string.

FIG. 9C depicts an embodiment of a drilling string including cuttingstructures positioned along the drilling string.

FIG. 10 depicts an embodiment of a drill bit including upward cuttingstructures.

FIG. 11 depicts an embodiment of a tubular including cutting structurespositioned in a wellbore.

FIG. 12 depicts a schematic drawing of an embodiment of a drillingsystem.

FIG. 13 depicts a schematic drawing of an embodiment of a drillingsystem for drilling into a hot formation.

FIG. 14 depicts a schematic drawing of an embodiment of a drillingsystem for drilling into a hot formation.

FIG. 15 depicts a schematic drawing of an embodiment of a drillingsystem for drilling into a hot formation.

FIG. 16 depicts an embodiment of a freeze well for a circulated liquidrefrigeration system, wherein a cutaway view of the freeze well isrepresented below ground surface.

FIG. 17A depicts an embodiment of a wellbore for introducing wax into aformation to form a wax grout barrier.

FIG. 17B depicts a representation of a wellbore drilled to anintermediate depth in a formation.

FIG. 17C depicts a representation of the wellbore drilled to the finaldepth in the formation.

FIG. 18 depicts an embodiment of a device for longitudinal welding of atubular using ERW.

FIGS. 19, 20, and 21 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section.

FIGS. 22, 23, 24, and 25 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section placedinside a sheath.

FIGS. 26A and 26B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 27A and 27B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 28A and 28B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 29A and 29B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 30A and 30B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIG. 31 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member.

FIG. 32 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member separating the conductors.

FIG. 33 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a support member.

FIG. 34 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a conduit support member.

FIG. 35 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit heat source.

FIG. 36 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source.

FIG. 37 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature of the ferromagnetic conductor.

FIGS. 38 and 39 depict embodiments of temperature limited heaters inwhich the jacket provides a majority of the heat output below the Curietemperature of the ferromagnetic conductor.

FIG. 40 depicts a high temperature embodiment of a temperature limitedheater.

FIG. 41 depicts hanging stress versus outside diameter for thetemperature limited heater shown in FIG. 37 with 347H as the supportmember.

FIG. 42 depicts hanging stress versus temperature for several materialsand varying outside diameters of the temperature limited heater.

FIGS. 43, 44, 45, and 46 depict examples of embodiments for temperaturelimited heaters that vary the materials and/or dimensions along thelength of the heaters to provide desired operating properties.

FIGS. 47 and 48 depict examples of embodiments for temperature limitedheaters that vary the diameter and/or materials of the support memberalong the length of the heaters to provide desired operating propertiesand sufficient mechanical properties.

FIGS. 49 and 49B depict cross-sectional representations of an embodimentof a temperature limited heater component used in an insulated conductorheater.

FIGS. 50 and 50B depict an embodiment of a system for installing heatersin a wellbore.

FIG. 50C depicts an embodiment of an insulated conductor with the sheathshorted to the conductors.

FIG. 51 depicts a top view representation of three insulated conductorsin a conduit.

FIG. 52 depicts an embodiment of three-phase wye transformer coupled toa plurality of heaters.

FIG. 53 depicts a side view representation of an end section of threeinsulated conductors in a conduit.

FIG. 54 depicts one alternative embodiment of a heater with threeinsulated cores in a conduit.

FIG. 55 depicts another alternative embodiment of a heater with threeinsulated conductors and an insulated return conductor in a conduit.

FIG. 56 depicts an embodiment of an insulated conductor heater in aconduit with molten metal.

FIG. 57 depicts an embodiment of a substantially horizontal insulatedconductor heater in a conduit with molten metal.

FIG. 58 depicts an embodiment for coupling together sections of a longtemperature limited heater.

FIG. 59 depicts an embodiment of a shield for orbital welding sectionsof a long temperature limited heater.

FIG. 60 depicts a schematic representation of an embodiment of a shutoff circuit for an orbital welding machine.

FIG. 61 depicts an embodiment of a temperature limited heater with a lowtemperature ferromagnetic outer conductor.

FIG. 62 depicts an embodiment of a temperature limitedconductor-in-conduit heater.

FIG. 63 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 64 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 65 depicts a cross-sectional view of an embodiment of aconductor-in-conduit temperature limited heater.

FIG. 66 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor.

FIG. 67 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor.

FIG. 68 depicts an embodiment of a three-phase temperature limitedheater with a portion shown in cross section.

FIG. 69 depicts an embodiment of temperature limited heaters coupledtogether in a three-phase configuration.

FIG. 70 depicts an embodiment of three heaters coupled in a three-phaseconfiguration.

FIG. 71 depicts a side view representation of an embodiment of asubstantially u-shaped three-phase heater.

FIG. 72 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a formation.

FIG. 73 depicts a top view representation of the embodiment depicted inFIG. 72 with production wells.

FIG. 74 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern.

FIG. 75 depicts a top view representation of an embodiment of a hexagonfrom FIG. 74.

FIG. 76 depicts an embodiment of triads of heaters coupled to ahorizontal bus bar.

FIGS. 77 and 78 depict embodiments for coupling contacting elements ofthree legs of a heater.

FIG. 79 depicts an embodiment of a container with an initiator formelting the coupling material.

FIG. 80 depicts an embodiment of a container for coupling contactingelements with bulbs on the contacting elements.

FIG. 81 depicts an alternative embodiment of a container.

FIG. 82 depicts an alternative embodiment for coupling contactingelements of three legs of a heater.

FIG. 83 depicts a cross-sectional representation of an embodiment forcoupling contacting elements using temperature limited heating elements.

FIG. 84 depicts a cross-sectional representation of an alternativeembodiment for coupling contacting elements using temperature limitedheating elements.

FIG. 85 depicts a cross-sectional representation of another alternativeembodiment for coupling contacting elements using temperature limitedheating elements.

FIG. 86 depicts a side view representation of an alternative embodimentfor coupling contacting elements of three legs of a heater.

FIG. 87 depicts a top view representation of the alternative embodimentfor coupling contacting elements of three legs of a heater depicted inFIG. 86.

FIG. 88 depicts an embodiment of a contacting element with a brushcontactor.

FIG. 89 depicts an embodiment for coupling contacting elements withbrush contactors.

FIG. 90 depicts an embodiment of two temperature limited heaters coupledtogether in a single contacting section.

FIG. 91 depicts an embodiment of two temperature limited heaters withlegs coupled in a contacting section.

FIG. 92 depicts an embodiment of three diads coupled to a three-phasetransformer.

FIG. 93 depicts an embodiment of groups of diads in a hexagonal pattern.

FIG. 94 depicts an embodiment of diads in a triangular pattern.

FIG. 95 depicts a side-view representation of an embodiment ofsubstantially u-shaped heaters.

FIG. 96 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 95.

FIG. 97 depicts a cross-sectional representation of substantiallyu-shaped heaters in a hydrocarbon layer.

FIG. 98 depicts a side view representation of an embodiment ofsubstantially vertical heaters coupled to a substantially horizontalwellbore.

FIG. 99 depicts an embodiment of pluralities of substantially horizontalheaters coupled to bus bars in a hydrocarbon layer

FIG. 100 depicts an alternative embodiment of pluralities ofsubstantially horizontal heaters coupled to bus bars in a hydrocarbonlayer.

FIG. 101 depicts an enlarged view of an embodiment of a bus bar coupledto heater with connectors.

FIG. 102 depicts an enlarged view of an embodiment of a bus bar coupledto a heater with connectors and centralizers.

FIG. 103 depicts a cross-sectional representation of a connectorcoupling to a bus bar.

FIG. 104 depicts a three-dimensional representation of a connectorcoupling to a bus bar.

FIG. 105 depicts an embodiment of a substantially u-shaped heater thatelectrically isolates itself from the formation.

FIG. 106 depicts an embodiment of a single-ended, substantiallyhorizontal heater that electrically isolates itself from the formation.

FIG. 107 depicts an embodiment of a single-ended, substantiallyhorizontal heater that electrically isolates itself from the formationusing an insulated conductor as the center conductor.

FIG. 108 depicts an embodiment of a single-ended, substantiallyhorizontal insulated conductor heater that electrically isolates itselffrom the formation.

FIGS. 109A and 109B depict cross-sectional representations of anembodiment of an insulated conductor that is electrically isolated onthe outside of the jacket.

FIGS. 110A and 110B depict an embodiment for using substantiallyu-shaped wellbores to time sequence heat two layers in a hydrocarboncontaining formation.

FIGS. 111A and 111B depict an embodiment for using horizontal wellboresto time sequence heat two layers in a hydrocarbon containing formation.

FIG. 112 depicts an embodiment of a wellhead.

FIG. 113 depicts an embodiment of a dual continuous tubular suspensionmechanism including threads cut on the dual continuous tubular over abuilt up portion.

FIG. 114 depicts an embodiment of a dual continuous tubular suspensionmechanism including a built up portion on a continuous tubular.

FIGS. 115A-B depict embodiments of dual continuous tubular suspensionmechanisms including slip mechanisms.

FIG. 116 depicts an embodiment of a dual continuous tubular suspensionmechanism including a slip mechanism and a screw lock system.

FIG. 117 depicts an embodiment of a dual continuous tubular suspensionmechanism including a slip mechanism and a screw lock system withcounter sunk bolts.

FIG. 118 depicts an embodiment of a pass-through fitting used to suspendtubulars.

FIG. 119 depicts an embodiment of a dual slip mechanism for inhibitingmovement of tubulars.

FIG. 120A-B depict embodiments of split suspension mechanisms and splitslip assemblies for hanging dual continuous tubulars.

FIG. 121 depicts an embodiment of a dual slip mechanism for inhibitingmovement of tubulars with a reverse configuration.

FIG. 122 depicts an embodiment of a two-part dual slip mechanism forinhibiting movement of tubulars.

FIG. 123 depicts an embodiment of a two-part dual slip mechanism forinhibiting movement of tubulars with separate locks.

FIG. 124 depicts an embodiment of a dual slip mechanism locking platefor inhibiting movement of tubulars.

FIG. 125 depicts an embodiment of a segmented dual slip mechanism withlocking screws for inhibiting movement of tubulars.

FIG. 126 depicts a top view representation of the embodiment of atransformer showing the windings and core of the transformer.

FIG. 127 depicts a side view representation of the embodiment of thetransformer showing the windings, the core, and the power leads.

FIG. 128 depicts an embodiment of a transformer in a wellbore.

FIG. 129 depicts an embodiment of a transformer in a wellbore with heatpipes.

FIG. 130 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a relativelythin hydrocarbon layer.

FIG. 131 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that is thicker than the hydrocarbon layer depicted in FIG. 130.

FIG. 132 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that is thicker than the hydrocarbon layer depicted in FIG. 131.

FIG. 133 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that has a shale break.

FIG. 134 depicts a top view representation of an embodiment forpreheating using heaters for the drive process.

FIG. 135 depicts a side view representation of an embodiment forpreheating using heaters for the drive process.

FIG. 136 depicts a representation of an embodiment for producinghydrocarbons from a tar sands formation.

FIG. 137 depicts a representation of an embodiment for producinghydrocarbons from multiple layers in a tar sands formation.

FIG. 138 depicts an embodiment for heating and producing from aformation with a temperature limited heater in a production wellbore.

FIG. 139 depicts an embodiment for heating and producing from aformation with a temperature limited heater and a production wellbore.

FIG. 140 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting.

FIG. 141 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting.

FIG. 142 depicts another embodiment of a heating/production assemblythat may be located in a wellbore for gas lifting.

FIG. 143 depicts an embodiment of a production conduit and a heater.

FIG. 144 depicts an embodiment for treating a formation.

FIG. 145 depicts an embodiment of a heater well with selective heating.

FIG. 146 depicts a schematic representation of an embodiment of adownhole oxidizer assembly.

FIG. 147 depicts a cross-sectional representation of an embodiment of adownhole oxidizer including an insulating sleeve.

FIG. 148 depicts a cross-sectional representation of an embodiment of adownhole oxidizer with a gas cooled insulating sleeve.

FIG. 149 depicts a perspective view of an embodiment of a portion of anoxidizer of a downhole oxidizer assembly.

FIG. 150 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 151 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 152 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 153 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 154 depicts a cross-sectional representation of an embodiment of anoxidizer shield with multiple flame stabilizers.

FIG. 155 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 156 depicts a perspective representation of an embodiment of asectioned oxidizer.

FIG. 157 depicts a perspective representation of an embodiment of asectioned oxidizer.

FIG. 158 depicts a perspective representation of an embodiment of asectioned oxidizer.

FIG. 159 depicts a perspective representation of an embodiment of aportion of an oxidizer of a downhole oxidizer assembly with louveredopenings in the shield.

FIG. 160 depicts a cross-sectional representation of a portion of ashield with a louvered opening.

FIG. 161 depicts a cross-sectional representation of an embodiment of afirst oxidizer of an oxidizer assembly.

FIG. 162 depicts a cross-sectional representation of an embodiment of acatalytic burner.

FIG. 163 depicts a cross-sectional representation of an embodiment of acatalytic burner with an igniter.

FIG. 164 depicts a schematic representation of an embodiment of a heaterthat uses coal as fuel.

FIG. 165 depicts a schematic representation of an embodiment of a heaterthat uses coal as fuel.

FIG. 166 depicts a schematic representation of a closed loop circulationsystem for heating a portion of a formation.

FIG. 167 depicts a plan view of wellbore entries and exits from aportion of a formation to be heated using a closed loop circulationsystem.

FIG. 168 depicts a schematic representation of an embodiment of an insitu heat treatment system that uses a nuclear reactor.

FIG. 169 depicts an elevational view of an in situ heat treatment systemusing pebble bed reactors.

FIG. 170 depicts a schematic of an embodiment of a U-shaped nuclearheater assembly.

FIG. 171 depicts a schematic of an embodiment of a nuclear heaterassembly.

FIG. 172 depicts a schematic an embodiment of a middle portion of anuclear heater assembly that includes pebble reactors and nuclearmoderators.

FIG. 173 depicts a schematic of an embodiment of an end portion of anuclear heater assembly that includes pebble reactors and nuclearmoderators.

FIG. 174 depicts a schematic of an embodiment of a nuclear heaterassembly that includes pebble reactors and spacers.

FIG. 175 depicts a schematic an embodiment of a nuclear heater assemblythat includes stacked pebble reactors.

FIG. 176 depicts a schematic an embodiment of an embodiment of nuclearheater assembly.

FIG. 177 depicts a side view representation of an embodiment of a systemfor heating the formation that can use a closed loop circulation systemand/or electrical heating.

FIG. 178 depicts a side view representation of an embodiment for an insitu staged heating and producing process for treating a tar sandsformation.

FIG. 179 depicts a top view of a rectangular checkerboard patternembodiment for the in situ staged heating and production process.

FIG. 180 depicts a top view of a ring pattern embodiment for the in situstaged heating and production process.

FIG. 181 depicts a top view of a checkerboard ring pattern embodimentfor the in situ staged heating and production process.

FIG. 182 depicts a top view an embodiment of a plurality of rectangularcheckerboard patterns in a treatment area for the in situ staged heatingand production process.

FIG. 183 depicts a side view representations of embodiments forproducing mobilized fluids from a hydrocarbon formation.

FIG. 184 depicts a schematic representation of a system for inhibitingmigration of formation fluid from a treatment area.

FIG. 185 depicts an embodiment of a windmill for generating electricityfor subsurface heaters.

FIG. 186 depicts an embodiment of a solution mining well.

FIG. 187 depicts a representation of a portion of a solution miningwell.

FIG. 188 depicts a representation of a portion of a solution miningwell.

FIG. 189 depicts an elevational view of a well pattern for solutionmining and/or an in situ heat treatment process.

FIG. 190 depicts a representation of wells of an in situ heatingtreatment process for solution mining and producing hydrocarbons from aformation.

FIG. 191 depicts an embodiment for solution mining a formation.

FIG. 192 depicts an embodiment of a formation with nahcolite layers inthe formation before solution mining nahcolite from the formation.

FIG. 193 depicts the formation of FIG. 192 after the nahcolite has beensolution mined.

FIG. 194 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.

FIG. 195 depicts an embodiment for heating a formation with dawsonite inthe formation.

FIG. 196 depicts a representation of an embodiment for solution miningwith a steam and electricity cogeneration facility.

FIG. 197 depicts an embodiment of treating a hydrocarbon containingformation with a combustion front.

FIG. 198 depicts a cross-sectional view of an embodiment of treating ahydrocarbon containing formation with a combustion front.

FIG. 199 depicts a schematic representation of a system for producingformation fluid and introducing sour gas into a subsurface formation.

FIG. 200 depicts electrical resistance versus temperature at variousapplied electrical currents for a 446 stainless steel rod.

FIG. 201 shows resistance profiles as a function of temperature atvarious applied electrical currents for a copper rod contained in aconduit of Sumitomo HCM12A.

FIG. 202 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 203 depicts raw data for a temperature limited heater.

FIG. 204 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 205 depicts power versus temperature at various applied electricalcurrents for a temperature limited heater.

FIG. 206 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 207 depicts data of electrical resistance versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied electrical currents.

FIG. 208 depicts data of electrical resistance versus temperature for acomposite 1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rodhas an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents.

FIG. 209 depicts data of power output versus temperature for a composite1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents.

FIG. 210 depicts data for values of skin depth versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied AC electrical currents.

FIG. 211 depicts temperature versus time for a temperature limitedheater.

FIG. 212 depicts temperature versus log time data for a 2.5 cm solid 410stainless steel rod and a 2.5 cm solid 304 stainless steel rod.

FIG. 213 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a stainless steel 347Hstainless steel support member.

FIG. 214 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,an iron-cobalt ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 215 depicts experimentally measured power factor versus temperatureat two AC currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 216 depicts experimentally measured turndown ratio versus maximumpower delivered for a temperature limited heater with a copper core, acarbon steel ferromagnetic conductor, and a 347H stainless steel supportmember.

FIG. 217 depicts examples of relative magnetic permeability versusmagnetic field for both the found correlations and raw data for carbonsteel.

FIG. 218 shows the resulting plots of skin depth versus magnetic fieldfor four temperatures and 400 A current.

FIG. 219 shows a comparison between the experimental and numerical(calculated) results for currents of 300 A, 400 A, and 500 A.

FIG. 220 shows the AC resistance per foot of the heater element as afunction of skin depth at 1100° F. calculated from the theoreticalmodel.

FIG. 221 depicts the power generated per unit length in each heatercomponent versus skin depth for a temperature limited heater.

FIGS. 222A-C compare the results of theoretical calculations withexperimental data for resistance versus temperature in a temperaturelimited heater.

FIG. 223 displays temperature of the center conductor of aconductor-in-conduit heater as a function of formation depth for a Curietemperature heater with a turndown ratio of 2:1.

FIG. 224 displays heater heat flux through a formation for a turndownratio of 2:1 along with the oil shale richness profile.

FIG. 225 displays heater temperature as a function of formation depthfor a turndown ratio of 3:1.

FIG. 226 displays heater heat flux through a formation for a turndownratio of 3:1 along with the oil shale richness profile.

FIG. 227 displays heater temperature as a function of formation depthfor a turndown ratio of 4:1.

FIG. 228 depicts heater temperature versus depth for heaters used in asimulation for heating oil shale.

FIG. 229 depicts heater heat flux versus time for heaters used in asimulation for heating oil shale.

FIG. 230 depicts accumulated heat input versus time in a simulation forheating oil shale.

FIG. 231 depicts a plot of heater power versus core diameter.

FIG. 232 depicts power, resistance, and current versus temperature for aheater with core diameters of 0.105″.

FIG. 233 depicts actual heater power versus time during the simulationfor three different heater designs.

FIG. 234 depicts heater element temperature (core temperature) andaverage formation temperature versus time for three different heaterdesigns.

FIG. 235 depicts cumulative gas production and cumulative oil productionversus time found from a STARS simulation using the heaters and heaterpattern depicted in FIGS. 70 and 72.

FIG. 236 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy TC3.

FIG. 237 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy FM-4.

FIG. 238 depicts the Curie temperature and phase transformationtemperature range for several iron alloys.

FIG. 239 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt and 0.4% by weight manganese.

FIG. 240 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.01% byweight carbon.

FIG. 241 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085% byweight carbon.

FIG. 242 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% by weightcarbon, and 0.4% by weight titanium.

FIG. 243 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-chromiumalloy having 12.25% by weight chromium, 0.1% by weight carbon, 0.5% byweight manganese, and 0.5% by weight silicon.

FIG. 244 depicts experimental calculation of weight percentages ofphases versus weight percentages of chromium in an alloy.

FIG. 245 depicts experimental calculation of weight percentages ofphases versus weight percentages of silicon in an alloy.

FIG. 246 depicts experimental calculation of weight percentages ofphases versus weight percentages of tungsten in an alloy.

FIG. 247 depicts experimental calculation of weight percentages ofphases versus weight percentages of niobium in an alloy.

FIG. 248 depicts experimental calculation of weight percentages ofphases versus weight percentages of carbon in an alloy.

FIG. 249 depicts experimental calculation of weight percentages ofphases versus weight percentages of nitrogen in an alloy.

FIG. 250 depicts experimental calculation of weight percentages ofphases versus weight percentages of titanium in an alloy.

FIG. 251 depicts experimental calculation of weight percentages ofphases versus weight percentages of copper in an alloy.

FIG. 252 depicts experimental calculation of weight percentages ofphases versus weight percentages of manganese in an alloy.

FIG. 253 depicts experimental calculation of weight percentages ofphases versus weight percentages of nickel in an alloy.

FIG. 254 depicts experimental calculation of weight percentages ofphases versus weight percentages of molybdenum in an alloy.

FIG. 255A depicts yield strengths and ultimate tensile strengths fordifferent metals.

FIG. 255B depicts yield strengths for different metals.

FIG. 255C depicts ultimate tensile strengths for different metals.

FIG. 255D depicts yield strengths for different metals.

FIG. 255E depicts ultimate tensile strengths for different metals.

FIG. 256 depicts projected corrosion rates over a one-year period forseveral metals in a sulfidation atmosphere.

FIG. 257 depicts projected corrosion rates over a one-year period for410 stainless steel and 410 stainless steel containing various amountsof cobalt in a sulfidation atmosphere.

FIG. 258 depicts an example of richness of an oil shale formation(gal/ton) versus depth (ft).

FIG. 259 depicts resistance per foot (mΩ/ft) versus temperature (° F.)profile of the first heater example.

FIG. 260 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the first example.

FIG. 261 depicts resistance per foot (mΩ/ft) versus temperature (° F.)for the second heater example.

FIG. 262 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the second example.

FIG. 263 depicts net heater energy input (Btu) versus time (days) forthe second example.

FIG. 264 depicts power injection per foot (W/ft) versus time (days) forthe second example.

FIG. 265 depicts resistance per foot (mΩ/ft) versus temperature (° F.)for the third heater example.

FIG. 266 depicts average temperature in the formation (° F.) versus time(days) as determined by the simulation for the third example.

FIG. 267 depicts cumulative energy injection (Btu) versus time (days)for each of the three heater examples.

FIG. 268 depicts average temperature (° F.) versus time (days) for thethird heater example with a 30 foot spacing between heaters in theformation as determined by the simulation.

FIG. 269 depicts average temperature (° F.) versus time (days) for thefourth heater example using the heater configuration and patterndepicted in FIGS. 70 and 72 as determined by the simulation.

FIG. 270 depicts a temperature profile in the formation after 360 daysusing the STARS simulation.

FIG. 271 depicts an oil saturation profile in the formation after 360days using the STARS simulation.

FIG. 272 depicts the oil saturation profile in the formation after 1095days using the STARS simulation.

FIG. 273 depicts the oil saturation profile in the formation after 1470days using the STARS simulation.

FIG. 274 depicts the oil saturation profile in the formation after 1826days using the STARS simulation.

FIG. 275 depicts the temperature profile in the formation after 1826days using the STARS simulation.

FIG. 276 depicts oil production rate and gas production rate versustime.

FIG. 277 depicts weight percentage of original bitumen in place(OBIP)(left axis) and volume percentage of OBIP (right axis) versustemperature (° C.).

FIG. 278 depicts bitumen conversion percentage (weight percentage of(OBIP))(left axis) and oil, gas, and coke weight percentage (as a weightpercentage of OBIP)(right axis) versus temperature (° C.).

FIG. 279 depicts API gravity (°)(left axis) of produced fluids, blowdown production, and oil left in place along with pressure (psig)(rightaxis) versus temperature (° C.).

FIG. 280A-D depict gas-to-oil ratios (GOR) in thousand cubic feet perbarrel ((Mcf/bbl)(y-axis) for versus temperature (° C.)(x-axis) fordifferent types of gas at a low temperature blow down (about 277° C.)and a high temperature blow down (at about 290° C.).

FIG. 281 depicts coke yield (weight percentage)(y-axis) versustemperature (° C.)(x-axis).

FIG. 282A-D depict assessed hydrocarbon isomer shifts in fluids producedfrom the experimental cells as a function of temperature and bitumenconversion.

FIG. 283 depicts weight percentage (Wt %)(y-axis) of saturates from SARAanalysis of the produced fluids versus temperature (° C.)(x-axis).

FIG. 284 depicts weight percentage (Wt %)(y-axis) of n-C₇ of theproduced fluids versus temperature (° C.)(x-axis).

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION

The following description generally relates to systems and methods fortreating hydrocarbons in the formations. Such formations may be treatedto yield hydrocarbon products, hydrogen, and other products.

“Alternating current (AC)” refers to a time-varying current thatreverses direction substantially sinusoidally. AC produces skin effectelectricity flow in a ferromagnetic conductor.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity isas determined by ASTM Method D6822 or ASTM Method D1298.

“ASTM” refers to American Standard Testing and Materials.

In the context of reduced heat output heating systems, apparatus, andmethods, the term “automatically” means such systems, apparatus, andmethods function in a certain way without the use of external control(for example, external controllers such as a controller with atemperature sensor and a feedback loop, PID controller, or predictivecontroller).

“Bare metal” and “exposed metal” refer to metals of elongated membersthat do not include a layer of electrical insulation, such as mineralinsulation, that is designed to provide electrical insulation for themetal throughout an operating temperature range of the elongated member.Bare metal and exposed metal may encompass a metal that includes acorrosion inhibiter such as a naturally occurring oxidation layer, anapplied oxidation layer, and/or a film. Bare metal and exposed metalinclude metals with polymeric or other types of electrical insulationthat cannot retain electrical insulating properties at typical operatingtemperature of the elongated member. Such material may be placed on themetal and may be thermally degraded during use of the heater.

Boiling range distributions for the formation fluid and liquid streamsdescribed herein are as determined by ASTM Method D5307 or ASTM MethodD2887. Content of hydrocarbon components in weight percent forparaffins, iso-paraffins, olefins, naphthenes and aromatics in theliquid streams is as determined by ASTM Method D6730. Content ofaromatics in volume percent is as determined by ASTM Method D1319. Theweight percentage of hydrogen is as determined by ASTM Method D3343.

“Carbon number” refers to the number of carbon atoms in a molecule. Ahydrocarbon fluid may include various hydrocarbons with different carbonnumbers. The hydrocarbon fluid may be described by a carbon numberdistribution. Carbon numbers and/or carbon number distributions may bedetermined by true boiling point distribution and/or gas-liquidchromatography.

“Cenospheres” refers to hollow particulate that are formed in thermalprocesses at high temperatures when molten components are blown up likeballoons by the volatilization of organic components.

“Chemically stability” refers to the ability of a formation fluid to betransported without components in the formation fluid reacting to formpolymers and/or compositions that plug pipelines, valves, and/orvessels.

“Clogging” refers to impeding and/or inhibiting flow of one or morecompositions through a process vessel or a conduit.

“Column X element” or “Column X elements” refer to one or more elementsof Column X of the Periodic Table, and/or one or more compounds of oneor more elements of Column X of the Periodic Table, in which Xcorresponds to a column number (for example, 13-18) of the PeriodicTable. For example, “Column 15 elements” refer to elements from Column15 of the Periodic Table and/or compounds of one or more elements fromColumn 15 of the Periodic Table.

“Column X metal” or “Column X metals” refer to one or more metals ofColumn X of the Periodic Table and/or one or more compounds of one ormore metals of Column X of the Periodic Table, in which X corresponds toa column number (for example, 1-12) of the Periodic Table. For example,“Column 6 metals” refer to metals from Column 6 of the Periodic Tableand/or compounds of one or more metals from Column 6 of the PeriodicTable.

“Condensable hydrocarbons” are hydrocarbons that condense at 25° C. andone atmosphere absolute pressure. Condensable hydrocarbons may include amixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

“Coring” is a process that generally includes drilling a hole into aformation and removing a substantially solid mass of the formation fromthe hole.

“Cracking” refers to a process involving decomposition and molecularrecombination of organic compounds to produce a greater number ofmolecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

“Curie temperature” is the temperature above which a ferromagneticmaterial loses all of its ferromagnetic properties. In addition tolosing all of its ferromagnetic properties above the Curie temperature,the ferromagnetic material begins to lose its ferromagnetic propertieswhen an increasing electrical current is passed through theferromagnetic material.

“Cycle oil” refers to a mixture of light cycle oil and heavy cycle oil.“Light cycle oil” refers to hydrocarbons having a boiling rangedistribution between 430° F. (221° C.) and 650° F. (343° C.) that areproduced from a fluidized catalytic cracking system. Light cycle oilcontent is determined by ASTM Method D5307. “Heavy cycle oil” refers tohydrocarbons having a boiling range distribution between 650° F. (343°C.) and 800° F. (427° C.) that are produced from a fluidized catalyticcracking system. Heavy cycle oil content is determined by ASTM MethodD5307.

“Diad” refers to a group of two items (for example, heaters, wellbores,or other objects) coupled together.

“Diesel” refers to hydrocarbons with a boiling range distributionbetween 260° C. and 343° C. (500-650° F.) at 0.101 MPa. Diesel contentis determined by ASTM Method D2887.

“Enriched air” refers to air having a larger mole fraction of oxygenthan air in the atmosphere. Air is typically enriched to increasecombustion-supporting ability of the air.

“Fluid pressure” is a pressure generated by a fluid in a formation.“Lithostatic pressure” (sometimes referred to as “lithostatic stress”)is a pressure in a formation equal to a weight per unit area of anoverlying rock mass. “Hydrostatic pressure” is a pressure in a formationexerted by a column of water.

A “formation” includes one or more hydrocarbon containing layers, one ormore non-hydrocarbon layers, an overburden, and/or an underburden.“Hydrocarbon layers” refer to layers in the formation that containhydrocarbons. The hydrocarbon layers may contain non-hydrocarbonmaterial and hydrocarbon material. The “overburden” and/or the“underburden” include one or more different types of impermeablematerials. For example, the overburden and/or underburden may includerock, shale, mudstone, or wet/tight carbonate. In some embodiments of insitu heat treatment processes, the overburden and/or the underburden mayinclude a hydrocarbon containing layer or hydrocarbon containing layersthat are relatively impermeable and are not subjected to temperaturesduring in situ heat treatment processing that result in significantcharacteristic changes of the hydrocarbon containing layers of theoverburden and/or the underburden. For example, the underburden maycontain shale or mudstone, but the underburden is not allowed to heat topyrolysis temperatures during the in situ heat treatment process. Insome cases, the overburden and/or the underburden may be somewhatpermeable.

“Formation fluids” refer to fluids present in a formation and mayinclude pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, andwater (steam). Formation fluids may include hydrocarbon fluids as wellas non-hydrocarbon fluids. The term “mobilized fluid” refers to fluidsin a hydrocarbon containing formation that are able to flow as a resultof thermal treatment of the formation. “Produced fluids” refer to fluidsremoved from the formation.

“Freezing point” of a hydrocarbon liquid refers to the temperature belowwhich solid hydrocarbon crystals may form in the liquid. Freezing pointis as determined by ASTM Method D5901.

“Gasoline hydrocarbons” refer to hydrocarbons having a boiling pointrange from 32° C. (90° F.) to about 204° C. (400° F.). Gasolinehydrocarbons include, but are not limited to, straight run gasoline,naphtha, fluidized or thermally catalytically cracked gasoline, VBgasoline, and coker gasoline. Gasoline hydrocarbons content isdetermined by ASTM Method D2887.

“Heat of Combustion” refers to an estimation of the net heat ofcombustion of a liquid. Heat of combustion is as determined by ASTMMethod D3338.

A “heat source” is any system for providing heat to at least a portionof a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and/or a conductordisposed in a conduit. A heat source may also include systems thatgenerate heat by burning a fuel external to or in a formation. Thesystems may be surface burners, downhole gas burners, flamelessdistributed combustors, and natural distributed combustors. In someembodiments, heat provided to or generated in one or more heat sourcesmay be supplied by other sources of energy. The other sources of energymay directly heat a formation, or the energy may be applied to atransfer medium that directly or indirectly heats the formation. It isto be understood that one or more heat sources that are applying heat toa formation may use different sources of energy. Thus, for example, fora given formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (for example, chemical reactions, solar energy, wind energy,biomass, or other sources of renewable energy). A chemical reaction mayinclude an exothermic reaction (for example, an oxidation reaction). Aheat source may also include a heater that provides heat to a zoneproximate and/or surrounding a heating location such as a heater well.

A “heater” is any system or heat source for generating heat in a well ora near wellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors that react with material in or producedfrom a formation, and/or combinations thereof.

“Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavy hydrocarbonsmay include highly viscous hydrocarbon fluids such as heavy oil, tar,and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, aswell as smaller concentrations of sulfur, oxygen, and nitrogen.Additional elements may also be present in heavy hydrocarbons in traceamounts. Heavy hydrocarbons may be classified by API gravity. Heavyhydrocarbons generally have an API gravity below about 20°. Heavy oil,for example, generally has an API gravity of about 10-20°, whereas targenerally has an API gravity below about 10°. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may include aromatics or other complex ringhydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. Therelatively permeable formation may include heavy hydrocarbons entrainedin, for example, sand or carbonate. “Relatively permeable” is defined,with respect to formations or portions thereof, as an averagepermeability of 10 millidarcy or more (for example, 10 or 100millidarcy).

“Relatively low permeability” is defined, with respect to formations orportions thereof, as an average permeability of less than about 10millidarcy. One darcy is equal to about 0.99 square micrometers. Animpermeable layer generally has a permeability of less than about 0.1millidarcy.

Certain types of formations that include heavy hydrocarbons may also be,but are not limited to, natural mineral waxes, or natural asphaltites.“Natural mineral waxes” typically occur in substantially tubular veinsthat may be several meters wide, several kilometers long, and hundredsof meters deep. “Natural asphaltites” include solid hydrocarbons of anaromatic composition and typically occur in large veins. In siturecovery of hydrocarbons from formations such as natural mineral waxesand natural asphaltites may include melting to form liquid hydrocarbonsand/or solution mining of hydrocarbons from the formations.

“Hydrocarbons” are generally defined as molecules formed primarily bycarbon and hydrogen atoms. Hydrocarbons may also include other elementssuch as, but not limited to, halogens, metallic elements, nitrogen,oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to,kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, andasphaltites. Hydrocarbons may be located in or adjacent to mineralmatrices in the earth. Matrices may include, but are not limited to,sedimentary rock, sands, silicilytes, carbonates, diatomites, and otherporous media. “Hydrocarbon fluids” are fluids that include hydrocarbons.Hydrocarbon fluids may include, entrain, or be entrained innon-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide,carbon dioxide, hydrogen sulfide, water, and ammonia.

An “in situ conversion process” refers to a process of heating ahydrocarbon containing formation from heat sources to raise thetemperature of at least a portion of the formation above a pyrolysistemperature so that pyrolyzation fluid is produced in the formation.

An “in situ heat treatment process” refers to a process of heating ahydrocarbon containing formation with heat sources to raise thetemperature of at least a portion of the formation above a temperaturethat results in mobilized fluid, visbreaking, and/or pyrolysis ofhydrocarbon containing material so that mobilized fluids, visbrokenfluids, and/or pyrolyzation fluids are produced in the formation.

“Insulated conductor” refers to any elongated material that is able toconduct electricity and that is covered, in whole or in part, by anelectrically insulating material.

“Karst” is a subsurface shaped by the dissolution of a soluble layer orlayers of bedrock, usually carbonate rock such as limestone or dolomite.The dissolution may be caused by meteoric or acidic water. The Grosmontformation in Alberta, Canada is an example of a karst (or “karsted”)carbonate formation.

“Kerogen” is a solid, insoluble hydrocarbon that has been converted bynatural degradation and that principally contains carbon, hydrogen,nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples ofmaterials that contain kerogen. “Bitumen” is a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide. “Oil” is a fluid containing a mixture of condensablehydrocarbons.

“Kerosene” refers to hydrocarbons with a boiling range distributionbetween 204° C. and 260° C. at 0.101 MPa. Kerosene content is determinedby ASTM Method D2887.

“Modulated direct current (DC)” refers to any substantiallynon-sinusoidal time-varying current that produces skin effectelectricity flow in a ferromagnetic conductor.

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution between 38° C. and 200° C. at 0.101 MPa. Naphtha content isdetermined by American Standard Testing and Materials ASTM Method D5307.

“Nitride” refers to a compound of nitrogen and one or more otherelements of the Periodic Table. Nitrides include, but are not limitedto, silicon nitride, boron nitride, or alumina nitride.

“Nitrogen compound content” refers to an amount of nitrogen in anorganic compound. Nitrogen content is as determined by ASTM MethodD5762.

“Octane Number” refers to a calculated numerical representation of theantiknock properties of a motor fuel compared to a standard referencefuel. A calculated octane number is determined by ASTM Method D6730.

“Olefins” are molecules that include unsaturated hydrocarbons having oneor more non-aromatic carbon-carbon double bonds.

“Orifices” refer to openings, such as openings in conduits, having awide variety of sizes and cross-sectional shapes including, but notlimited to, circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes.

“Pebble” refers to one or more spheres, oval shapes, oblong shapes,irregular or elongated shapes.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC), November2003. In the scope of this application, weight of a metal from thePeriodic Table, weight of a compound of a metal from the Periodic Table,weight of an element from the Periodic Table, or weight of a compound ofan element from the Periodic Table is calculated as the weight of metalor the weight of element. For example, if 0.1 grams of MoO3 is used pergram of catalyst, the calculated weight of the molybdenum metal in thecatalyst is 0.067 grams per gram of catalyst.

“Physical stability” refers the ability of a formation fluid to notexhibit phase separate or flocculation during transportation of thefluid. Physical stability is determined by ASTM Method D7060.

“Pyrolysis” is the breaking of chemical bonds due to the application ofheat. For example, pyrolysis may include transforming a compound intoone or more other substances by heat alone. Heat may be transferred to asection of the formation to cause pyrolysis.

“Pyrolyzation fluids” or “pyrolysis products” refers to fluid producedsubstantially during pyrolysis of hydrocarbons. Fluid produced bypyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation (forexample, a relatively permeable formation such as a tar sands formation)that is reacted or reacting to form a pyrolyzation fluid.

“Residue” refers to hydrocarbons that have a boiling point above 537° C.(1000° F.).

“Rich layers” in a hydrocarbon containing formation are relatively thinlayers (typically about 0.2 m to about 0.5 m thick). Rich layersgenerally have a richness of about 0.150 L/kg or greater. Some richlayers have a richness of about 0.170 L/kg or greater, of about 0.190L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of theformation have a richness of about 0.100 L/kg or less and are generallythicker than rich layers. The richness and locations of layers aredetermined, for example, by coring and subsequent Fischer assay of thecore, density or neutron logging, or other logging methods. Rich layersmay have a lower initial thermal conductivity than other layers of theformation. Typically, rich layers have a thermal conductivity 1.5 timesto 3 times lower than the thermal conductivity of lean layers. Inaddition, rich layers have a higher thermal expansion coefficient thanlean layers of the formation.

“Smart well technology” or “smart wellbore” refers to wells thatincorporate downhole measurement and/or control. For injection wells,smart well technology may allow for controlled injection of fluid intothe formation in desired zones. For production wells, smart welltechnology may allow for controlled production of formation fluid fromselected zones. Some wells may include smart well technology that allowsfor formation fluid production from selected zones and simultaneous orstaggered solution injection into other zones. Smart well technology mayinclude fiber optic systems and control valves in the wellbore. A smartwellbore used for an in situ heat treatment process may be WestbayMultilevel Well System MP55 available from Westbay Instruments Inc.(Burnaby, British Columbia, Canada).

“Subsidence” is a downward movement of a portion of a formation relativeto an initial elevation of the surface.

“Sulfur compound content” refers to an amount of sulfur in an organiccompound. Sulfur content is as determined by ASTM Method D4294.

“Superposition of heat” refers to providing heat from two or more heatsources to a selected section of a formation such that the temperatureof the formation at least at one location between the heat sources isinfluenced by the heat sources.

“Synthesis gas” is a mixture including hydrogen and carbon monoxide.Additional components of synthesis gas may include water, carbondioxide, nitrogen, methane, and other gases. Synthesis gas may begenerated by a variety of processes and feedstocks. Synthesis gas may beused for synthesizing a wide range of compounds.

“TAN” refers to a total acid number expressed as milligrams (“mg”) ofKOH per gram (“g”) of sample. TAN is as determined by ASTM Method D3242.

“Tar” is a viscous hydrocarbon that generally has a viscosity greaterthan about 10,000 centipoise at 15° C. The specific gravity of targenerally is greater than 1.000. Tar may have an API gravity less than10°.

A “tar sands formation” is a formation in which hydrocarbons arepredominantly present in the form of heavy hydrocarbons and/or tarentrained in a mineral grain framework or other host lithology (forexample, sand or carbonate). Examples of tar sands formations includeformations such as the Athabasca formation, the Grosmont formation, andthe Peace River formation, all three in Alberta, Canada; and the Fajaformation in the Orinoco belt in Venezuela.

“Temperature limited heater” generally refers to a heater that regulatesheat output (for example, reduces heat output) above a specifiedtemperature without the use of external controls such as temperaturecontrollers, power regulators, rectifiers, or other devices. Temperaturelimited heaters may be AC (alternating current) or modulated (forexample, “chopped”) DC (direct current) powered electrical resistanceheaters.

“Thermally conductive fluid” includes fluid that has a higher thermalconductivity than air at standard temperature and pressure (STP) (0° C.and 101.325 kPa).

“Thermal conductivity” is a property of a material that describes therate at which heat flows, in steady state, between two surfaces of thematerial for a given temperature difference between the two surfaces.

“Thermal fracture” refers to fractures created in a formation caused byexpansion or contraction of a formation and/or fluids in the formation,which is in turn caused by increasing/decreasing the temperature of theformation and/or fluids in the formation, and/or byincreasing/decreasing a pressure of fluids in the formation due toheating.

“Thermal oxidation stability” refers to thermal oxidation stability of aliquid. Thermal Oxidation Stability is as determined by ASTM MethodD3241.

“Thickness” of a layer refers to the thickness of a cross section of thelayer, wherein the cross section is normal to a face of the layer.

“Time-varying current” refers to electrical current that produces skineffect electricity flow in a ferromagnetic conductor and has a magnitudethat varies with time. Time-varying current includes both alternatingcurrent (AC) and modulated direct current (DC).

“Triad” refers to a group of three items (for example, heaters,wellbores, or other objects) coupled together.

“Turndown ratio” for the temperature limited heater is the ratio of thehighest AC or modulated DC resistance below the Curie temperature to thelowest resistance above the Curie temperature for a given current.

A “u-shaped wellbore” refers to a wellbore that extends from a firstopening in the formation, through at least a portion of the formation,and out through a second opening in the formation. In this context, thewellbore may be only roughly in the shape of a “v” or “u”, with theunderstanding that the “legs” of the “u” do not need to be parallel toeach other, or perpendicular to the “bottom” of the “u” for the wellboreto be considered “u-shaped”.

“Upgrade” refers to increasing the quality of hydrocarbons. For example,upgrading heavy hydrocarbons may result in an increase in the APIgravity of the heavy hydrocarbons.

“Visbreaking” refers to the untangling of molecules in fluid during heattreatment and/or to the breaking of large molecules into smallermolecules during heat treatment, which results in a reduction of theviscosity of the fluid.

“Viscosity” refers to kinematic viscosity at 40° C. unless specified.Viscosity is as determined by ASTM Method D445.

“VGO” or “vacuum gas oil” refers to hydrocarbons with a boiling rangedistribution between 343° C. and 538° C. at 0.101 MPa. VGO content isdetermined by ASTM Method D5307.

A “vug” is a cavity, void or large pore in a rock that is commonly linedwith mineral precipitates.

“Wax” refers to a low melting organic mixture, or a compound of highmolecular weight that is a solid at lower temperatures and a liquid athigher temperatures, and when in solid form can form a barrier to water.Examples of waxes include animal waxes, vegetable waxes, mineral waxes,petroleum waxes, and synthetic waxes.

The term “wellbore” refers to a hole in a formation made by drilling orinsertion of a conduit into the formation. A wellbore may have asubstantially circular cross section, or another cross-sectional shape.As used herein, the terms “well” and “opening,” when referring to anopening in the formation may be used interchangeably with the term“wellbore.”

Hydrocarbons in formations may be treated in various ways to producemany different products. In certain embodiments, hydrocarbons informations are treated in stages. FIG. 1 depicts an illustration ofstages of heating the hydrocarbon containing formation. FIG. 1 alsodepicts an example of yield (“Y”) in barrels of oil equivalent per ton(y axis) of formation fluids from the formation versus temperature (“T”)of the heated formation in degrees Celsius (x axis).

Desorption of methane and vaporization of water occurs during stage 1heating. Heating of the formation through stage 1 may be performed asquickly as possible. For example, when the hydrocarbon containingformation is initially heated, hydrocarbons in the formation desorbadsorbed methane. The desorbed methane may be produced from theformation. If the hydrocarbon containing formation is heated further,water in the hydrocarbon containing formation is vaporized. Water mayoccupy, in some hydrocarbon containing formations, between 10% and 50%of the pore volume in the formation. In other formations, water occupieslarger or smaller portions of the pore volume. Water typically isvaporized in a formation between 160° C. and 285° C. at pressures of 600kPa absolute to 7000 kPa absolute. In some embodiments, the vaporizedwater produces wettability changes in the formation and/or increasedformation pressure. The wettability changes and/or increased pressuremay affect pyrolysis reactions or other reactions in the formation. Incertain embodiments, the vaporized water is produced from the formation.In other embodiments, the vaporized water is used for steam extractionand/or distillation in the formation or outside the formation. Removingthe water from and increasing the pore volume in the formation increasesthe storage space for hydrocarbons in the pore volume.

In certain embodiments, after stage 1 heating, the formation is heatedfurther, such that a temperature in the formation reaches (at least) aninitial pyrolyzation temperature (such as a temperature at the lower endof the temperature range shown as stage 2). Hydrocarbons in theformation may be pyrolyzed throughout stage 2. A pyrolysis temperaturerange varies depending on the types of hydrocarbons in the formation.The pyrolysis temperature range may include temperatures between 250° C.and 900° C. The pyrolysis temperature range for producing desiredproducts may extend through only a portion of the total pyrolysistemperature range. In some embodiments, the pyrolysis temperature rangefor producing desired products may include temperatures between 250° C.and 400° C. or temperatures between 270° C. and 350° C. If a temperatureof hydrocarbons in the formation is slowly raised through thetemperature range from 250° C. to 400° C., production of pyrolysisproducts may be substantially complete when the temperature approaches400° C. Average temperature of the hydrocarbons may be raised at a rateof less than 5° C. per day, less than 2° C. per day, less than 1° C. perday, or less than 0.5° C. per day through the pyrolysis temperaturerange for producing desired products. Heating the hydrocarbon containingformation with a plurality of heat sources may establish thermalgradients around the heat sources that slowly raise the temperature ofhydrocarbons in the formation through the pyrolysis temperature range.

The rate of temperature increase through the pyrolysis temperature rangefor desired products may affect the quality and quantity of theformation fluids produced from the hydrocarbon containing formation.Raising the temperature slowly through the pyrolysis temperature rangefor desired products may inhibit mobilization of large chain moleculesin the formation. Raising the temperature slowly through the pyrolysistemperature range for desired products may limit reactions betweenmobilized hydrocarbons that produce undesired products. Slowly raisingthe temperature of the formation through the pyrolysis temperature rangefor desired products may allow for the production of high quality, highAPI gravity hydrocarbons from the formation. Slowly raising thetemperature of the formation through the pyrolysis temperature range fordesired products may allow for the removal of a large amount of thehydrocarbons present in the formation as hydrocarbon product.

In some in situ heat treatment embodiments, a portion of the formationis heated to a desired temperature instead of slowly heating thetemperature through a temperature range. In some embodiments, thedesired temperature is 300° C., 325° C., or 350° C. Other temperaturesmay be selected as the desired temperature. Superposition of heat fromheat sources allows the desired temperature to be relatively quickly andefficiently established in the formation. Energy input into theformation from the heat sources may be adjusted to maintain thetemperature in the formation substantially at the desired temperature.The heated portion of the formation is maintained substantially at thedesired temperature until pyrolysis declines such that production ofdesired formation fluids from the formation becomes uneconomical. Partsof the formation that are subjected to pyrolysis may include regionsbrought into a pyrolysis temperature range by heat transfer from onlyone heat source.

In certain embodiments, formation fluids including pyrolyzation fluidsare produced from the formation. As the temperature of the formationincreases, the amount of condensable hydrocarbons in the producedformation fluid may decrease. At high temperatures, the formation mayproduce mostly methane and/or hydrogen. If the hydrocarbon containingformation is heated throughout an entire pyrolysis range, the formationmay produce only small amounts of hydrogen towards an upper limit of thepyrolysis range. After all of the available hydrogen is depleted, aminimal amount of fluid production from the formation will typicallyoccur.

After pyrolysis of hydrocarbons, a large amount of carbon and somehydrogen may still be present in the formation. A significant portion ofcarbon remaining in the formation can be produced from the formation inthe form of synthesis gas. Synthesis gas generation may take placeduring stage 3 heating depicted in FIG. 1. Stage 3 may include heating ahydrocarbon containing formation to a temperature sufficient to allowsynthesis gas generation. For example, synthesis gas may be produced ina temperature range from about 400° C. to about 1200° C., about 500° C.to about 1100° C., or about 550° C. to about 1000° C. The temperature ofthe heated portion of the formation when the synthesis gas generatingfluid is introduced to the formation determines the composition ofsynthesis gas produced in the formation. The generated synthesis gas maybe removed from the formation through a production well or productionwells.

Total energy content of fluids produced from the hydrocarbon containingformation may stay relatively constant throughout pyrolysis andsynthesis gas generation. During pyrolysis at relatively low formationtemperatures, a significant portion of the produced fluid may becondensable hydrocarbons that have a high energy content. At higherpyrolysis temperatures, however, less of the formation fluid may includecondensable hydrocarbons. More non-condensable formation fluids may beproduced from the formation. Energy content per unit volume of theproduced fluid may decline slightly during generation of predominantlynon-condensable formation fluids. During synthesis gas generation,energy content per unit volume of produced synthesis gas declinessignificantly compared to energy content of pyrolyzation fluid. Thevolume of the produced synthesis gas, however, will in many instancesincrease substantially, thereby compensating for the decreased energycontent.

FIG. 2 depicts a schematic view of an embodiment of a portion of the insitu heat treatment system for treating the hydrocarbon containingformation. The in situ heat treatment system may include barrier wells200. Barrier wells are used to form a barrier around a treatment area.The barrier inhibits fluid flow into and/or out of the treatment area.Barrier wells include, but are not limited to, dewatering wells, vacuumwells, capture wells, injection wells, grout wells, freeze wells, orcombinations thereof. In some embodiments, barrier wells 200 aredewatering wells. Dewatering wells may remove liquid water and/orinhibit liquid water from entering a portion of the formation to beheated, or to the formation being heated. In the embodiment depicted inFIG. 2, the barrier wells 200 are shown extending only along one side ofheat sources 202, but the barrier wells typically encircle all heatsources 202 used, or to be used, to heat a treatment area of theformation.

Heat sources 202 are placed in at least a portion of the formation. Heatsources 202 may include heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 202 mayalso include other types of heaters. Heat sources 202 provide heat to atleast a portion of the formation to heat hydrocarbons in the formation.Energy may be supplied to heat sources 202 through supply lines 204.Supply lines 204 may be structurally different depending on the type ofheat source or heat sources used to heat the formation. Supply lines 204for heat sources may transmit electricity for electric heaters, maytransport fuel for combustors, or may transport heat exchange fluid thatis circulated in the formation. In some embodiments, electricity for anin situ heat treatment process may be provided by a nuclear power plantor nuclear power plants. The use of nuclear power may allow forreduction or elimination of carbon dioxide emissions from the in situheat treatment process.

When the formation is heated, the heat input into the formation maycause expansion of the formation and geomechanical motion. Heat sourcesmay be turned on before, at the same time, or during a dewateringprocess. Computer simulations may model formation response to heating.The computer simulations may be used to develop a pattern and timesequence for activating heat sources in the formation so thatgeomechanical motion of the formation does not adversely affect thefunctionality of heat sources, production wells, and other equipment inthe formation.

Heating the formation may cause an increase in permeability and/orporosity of the formation. Increases in permeability and/or porosity mayresult from a reduction of mass in the formation due to vaporization andremoval of water, removal of hydrocarbons, and/or creation of fractures.Fluid may flow more easily in the heated portion of the formationbecause of the increased permeability and/or porosity of the formation.Fluid in the heated portion of the formation may move a considerabledistance through the formation because of the increased permeabilityand/or porosity. The considerable distance may be over 1000 m dependingon various factors, such as permeability of the formation, properties ofthe fluid, temperature of the formation, and pressure gradient allowingmovement of the fluid. The ability of fluid to travel considerabledistance in the formation allows production wells 206 to be spacedrelatively far apart in the formation.

Production wells 206 are used to remove formation fluid from theformation. In some embodiments, production well 206 includes a heatsource. The heat source in the production well may heat one or moreportions of the formation at or near the production well. In some insitu heat treatment process embodiments, the amount of heat supplied tothe formation from the production well per meter of the production wellis less than the amount of heat applied to the formation from a heatsource that heats the formation per meter of the heat source. Heatapplied to the formation from the production well may increase formationpermeability adjacent to the production well by vaporizing and removingliquid phase fluid adjacent to the production well and/or by increasingthe permeability of the formation adjacent to the production well byformation of macro and/or micro fractures.

More than one heat source may be positioned in the production well. Aheat source in a lower portion of the production well may be turned offwhen superposition of heat from adjacent heat sources heats theformation sufficiently to counteract benefits provided by heating theformation with the production well. In some embodiments, the heat sourcein an upper portion of the production well may remain on after the heatsource in the lower portion of the production well is deactivated. Theheat source in the upper portion of the well may inhibit condensationand reflux of formation fluid.

In some embodiments, the heat source in production well 206 allows forvapor phase removal of formation fluids from the formation. Providingheating at or through the production well may: (1) inhibit condensationand/or refluxing of production fluid when such production fluid ismoving in the production well proximate the overburden, (2) increaseheat input into the formation, (3) increase production rate from theproduction well as compared to a production well without a heat source,(4) inhibit condensation of high carbon number compounds (C6 and above)in the production well, and/or (5) increase formation permeability at orproximate the production well.

Subsurface pressure in the formation may correspond to the fluidpressure generated in the formation. As temperatures in the heatedportion of the formation increase, the pressure in the heated portionmay increase as a result of increased fluid generation and vaporizationof water. Controlling rate of fluid removal from the formation may allowfor control of pressure in the formation. Pressure in the formation maybe determined at a number of different locations, such as near or atproduction wells, near or at heat sources, or at monitor wells.

In some hydrocarbon containing formations, production of hydrocarbonsfrom the formation is inhibited until at least some hydrocarbons in theformation have been pyrolyzed. Formation fluid may be produced from theformation when the formation fluid is of a selected quality. In someembodiments, the selected quality includes an API gravity of at leastabout 20°, 30°, or 40°. Inhibiting production until at least somehydrocarbons are pyrolyzed may increase conversion of heavy hydrocarbonsto light hydrocarbons. Inhibiting initial production may minimize theproduction of heavy hydrocarbons from the formation. Production ofsubstantial amounts of heavy hydrocarbons may require expensiveequipment and/or reduce the life of production equipment.

In some hydrocarbon containing formations, hydrocarbons in the formationmay be heated to pyrolysis temperatures before substantial permeabilityhas been generated in the heated portion of the formation. An initiallack of permeability may inhibit the transport of generated fluids toproduction wells 206. During initial heating, fluid pressure in theformation may increase proximate heat sources 202. The increased fluidpressure may be released, monitored, altered, and/or controlled throughone or more heat sources 202. For example, selected heat sources 202 orseparate pressure relief wells may include pressure relief valves thatallow for removal of some fluid from the formation.

In some embodiments, pressure generated by expansion of pyrolysis fluidsor other fluids generated in the formation may be allowed to increasealthough an open path to production wells 206 or any other pressure sinkmay not yet exist in the formation. The fluid pressure may be allowed toincrease towards a lithostatic pressure. Fractures in the hydrocarboncontaining formation may form when the fluid approaches the lithostaticpressure. For example, fractures may form from heat sources 202 toproduction wells 206 in the heated portion of the formation. Thegeneration of fractures in the heated portion may relieve some of thepressure in the portion. Pressure in the formation may have to bemaintained below a selected pressure to inhibit unwanted production,fracturing of the overburden or underburden, and/or coking ofhydrocarbons in the formation.

After pyrolysis temperatures are reached and production from theformation is allowed, pressure in the formation may be varied to alterand/or control a composition of formation fluid produced, to control apercentage of condensable fluid as compared to non-condensable fluid inthe formation fluid, and/or to control an API gravity of formation fluidbeing produced. For example, decreasing pressure may result inproduction of a larger condensable fluid component. The condensablefluid component may contain a larger percentage of olefins.

In some in situ heat treatment process embodiments, pressure in theformation may be maintained high enough to promote production offormation fluid with an API gravity of greater than 20°. Maintainingincreased pressure in the formation may inhibit formation subsidenceduring in situ heat treatment. Maintaining increased pressure mayfacilitate vapor phase production of fluids from the formation. Vaporphase production may allow for a reduction in size of collectionconduits used to transport fluids produced from the formation.Maintaining increased pressure may reduce or eliminate the need tocompress formation fluids at the surface to transport the fluids incollection conduits to treatment facilities.

Maintaining increased pressure in a heated portion of the formation maysurprisingly allow for production of large quantities of hydrocarbons ofincreased quality and of relatively low molecular weight. Pressure maybe maintained so that formation fluid produced has a minimal amount ofcompounds above a selected carbon number. The selected carbon number maybe at most 25, at most 20, at most 12, or at most 8. Some high carbonnumber compounds may be entrained in vapor in the formation and may beremoved from the formation with the vapor. Maintaining increasedpressure in the formation may inhibit entrainment of high carbon numbercompounds and/or multi-ring hydrocarbon compounds in the vapor. Highcarbon number compounds and/or multi-ring hydrocarbon compounds mayremain in a liquid phase in the formation for significant time periods.The significant time periods may provide sufficient time for thecompounds to pyrolyze to form lower carbon number compounds.

Generation of relatively low molecular weight hydrocarbons is believedto be due, in part, to autogenous generation and reaction of hydrogen ina portion of the hydrocarbon containing formation. For example,maintaining an increased pressure may force hydrogen generated duringpyrolysis into the liquid phase within the formation. Heating theportion to a temperature in a pyrolysis temperature range may pyrolyzehydrocarbons in the formation to generate liquid phase pyrolyzationfluids. The generated liquid phase pyrolyzation fluids components mayinclude double bonds and/or radicals. Hydrogen (H₂) in the liquid phasemay reduce double bonds of the generated pyrolyzation fluids, therebyreducing a potential for polymerization or formation of long chaincompounds from the generated pyrolyzation fluids. In addition, H₂ mayalso neutralize radicals in the generated pyrolyzation fluids.Therefore, H₂ in the liquid phase may inhibit the generated pyrolyzationfluids from reacting with each other and/or with other compounds in theformation.

Formation fluid produced from production wells 206 may be transportedthrough collection piping 208 to treatment facilities 210. Formationfluids may also be produced from heat sources 202. For example, fluidmay be produced from heat sources 202 to control pressure in theformation adjacent to the heat sources. Fluid produced from heat sources202 may be transported through tubing or piping to collection piping 208or the produced fluid may be transported through tubing or pipingdirectly to treatment facilities 210. Treatment facilities 210 mayinclude separation units, reaction units, upgrading units, fuel cells,turbines, storage vessels, and/or other systems and units for processingproduced formation fluids. The treatment facilities may formtransportation fuel from at least a portion of the hydrocarbons producedfrom the formation. In some embodiments, the transportation fuel may bejet fuel, such as JP-8.

Formation fluid may be hot when produced from the formation through theproduction wells. Hot formation fluid may be produced during solutionmining processes and/or during in situ heat treatment processes. In someembodiments, electricity may be generated using the heat of the fluidproduced from the formation. Also, heat recovered from the formationafter the in situ process may be used to generate electricity. Thegenerated electricity may be used to supply power to the in situ heattreatment process. For example, the electricity may be used to powerheaters, or to power a refrigeration system for forming or maintaining alow temperature barrier. Electricity may be generated using a Kalinacycle or a modified Kalina cycle.

FIG. 3 depicts a schematic representation of a Kalina cycle that usesrelatively high pressure aqua ammonia as the working fluid. In otherembodiments, other fluids such as alkanes, hydrochlorofluorocarbons,hydrofluorocarbons, or carbon dioxide may be used as the working fluid.Hot produced fluid from the formation may pass through line 212 to heatexchanger 214. The produced fluid may have a temperature greater thanabout 100° C. Line 216 from heat exchanger 214 may direct the producedfluid to a separator or other treatment unit. In some embodiments, theproduced fluid is a mineral containing fluid produced during solutionmining. In some embodiments, the produced fluid includes hydrocarbonsproduced using an in situ heat treatment process or using an in situmobilization process. Heat from the produced fluid is used to evaporateaqua ammonia in heat exchanger 214.

Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger 214and heat exchanger 222. Aqua ammonia from heat exchangers 214, 222passes to separator 224. Separator 224 forms a rich ammonia gas streamand a lean ammonia gas stream. The rich ammonia gas stream is sent toturbine 226 to generate electricity.

The lean ammonia gas stream from separator 224 passes through heatexchanger 222. The lean gas stream leaving heat exchanger 222 iscombined with the rich ammonia gas stream leaving turbine 226. Thecombination stream is passed through heat exchanger 228 and returned totank 218. Heat exchanger 228 may be water cooled. Heater water from heatexchanger 228 may be sent to a surface water reservoir through line 230.

FIG. 4 depicts a schematic representation of a modified Kalina cyclethat uses lower pressure aqua ammonia as the working fluid. In otherembodiments, other fluids such as alkanes, hydrochlorofluorcarbons,hydrofluorocarbons, or carbon dioxide may be used as the working fluid.Hot produced fluid from the formation may pass through line 212 to heatexchanger 214. The produced fluid may have a temperature greater thanabout 100° C. Second heat exchanger 232 may further reduce thetemperature of the produced fluid from the formation before the fluid issent through line 216 to a separator or other treatment unit. Secondheat exchanger may be water cooled.

Aqua ammonia from tank 218 is directed by pump 220 to heat exchanger234. The temperature of the aqua ammonia from tank 218 is raised in heatexchanger 234 by heat transfer with a combined aqua ammonia stream fromturbine 226 and separator 224. The aqua ammonia stream from heatexchanger 234 passes to heat exchanger 236. The temperature of thestream is raised again by transfer of heat with a lean ammonia streamthat exits separator 224. The stream then passes to heat exchanger 214.Heat from the produced fluid is used to evaporate aqua ammonia in heatexchanger 214. The aqua ammonia passes to separator 224.

Separator 224 forms a rich ammonia gas stream and a lean ammonia gasstream. The rich ammonia gas stream is sent to turbine 226 to generateelectricity. The lean ammonia gas stream passes through heat exchanger236. After heat exchanger 236, the lean ammonia gas stream is combinedwith the rich ammonia gas stream leaving turbine 226. The combined gasstream is passed through heat exchanger 234 to cooler 238. After cooler238, the stream returns to tank 218.

Heating a portion of the subsurface formation may cause the mineralstructure of the formation to change and form particles. The particlesmay be dispersed and/or become partially dissolved in the formationfluid. The particles may include metals and/or compounds of metals fromColumns 1-2 and Columns 4-13 of the Periodic Table (for example,aluminum, silicon, magnesium, calcium, potassium sodium, beryllium,lithium, chromium, magnesium, copper, zirconium, and so forth). Incertain embodiments, the particles include cenospheres. In someembodiments, the particles are coated, for example, with hydrocarbons ofthe formation fluid. In certain embodiments, the particles includezeolites.

A concentration of particles in formation fluid may range from about 1ppm to about 3000 ppm, from about 50 ppm to about 2000 ppm, or fromabout 100 ppm to about 1000 ppm. The size of particles may range fromabout 0.5 micrometers to about 200 micrometers, from about 5 micrometersto about 150 micrometers, from about 10 micrometers to about 100micrometers, or about 20 micrometers to about 50 micrometers.

In certain embodiments, formation fluid may include a distribution ofparticles. The distribution of particles may be, but is not limited to,a trimodal or a bimodal distribution. For example, a trimodaldistribution of particles may include from about 1 ppm to about 50 ppmof particles with a size of about 5 micrometers to about 10 micrometers,from about 2 ppm to about 2000 ppm of particles with a size of about 50micrometers to about 80 micrometers, and from about 1 ppm to about 100ppm with a size of between about 100 micrometers and about 200micrometers. A bimodal distribution of particles may include from about1 ppm to about 60 ppm of particles with a size of between about 50micrometers and about 60 micrometers and from about 2 ppm to about 2000ppm of particles with a size between about 100 micrometers and about 200micrometers.

In some embodiments, the particles may contact the formation fluid andcatalyze formation of compounds having a carbon number of at most 25, atmost 20, at most 12, or at most 8. In certain embodiments, zeoliticparticles may assist in the oxidation and/or reduction of formationfluids to produce compounds not generally found in fluids produced usingconventional production methods. Contact of formation fluid withhydrogen in the presence of zeolitic particles may catalyze reduction ofdouble bond compounds in the formation fluid.

In some embodiments, all or a portion of the particles in the producedfluid may be removed from the produced fluid. The particles may beremoved by using a centrifuge, by washing, by acid washing, byfiltration, by electrostatic precipitation, by froth flotation, and/orby another type of separation process.

Formation fluid produced from the in situ heat treatment process may besent to the separator to split the stream into the in situ heattreatment process liquid stream and an in situ heat treatment processgas stream. In some embodiments, the formation fluid has a boiling rangedistribution between about −5° C. and about 350° C., between about 5° C.and about 340° C., between about 10° C. and about 330° C., or betweenabout 15° C. and about 320° C.

The liquid stream and the gas stream may be further treated to yielddesired products. When the liquid stream is treated using generallyknown conditions to produce commercial products, processing equipmentmay be adversely affected. For example, the processing equipment mayclog. Examples of processes to produce commercial products include, butare not limited to, alkylation, distillation, catalytic reforminghydrocracking, hydrotreating, hydrogenation, hydrodesulfurization,catalytic cracking, delayed coking, gasification, or combinationsthereof. Processes to produce hydrocarbon streams and/or other productsare described in “Refining Processes 2000,” Hydrocarbon Processing, GulfPublishing Co., pp. 87-142, which is incorporated by reference herein.Examples of commercial hydrocarbon products include, but are not limitedto, diesel, hydrocarbon gases, kerosene, naphtha, vacuum gas oil(“VGO”), or mixtures thereof.

Process equipment may become clogged or fouled by compositions in the insitu heat treatment process liquid. Clogging compositions may include,but are not limited to, hydrocarbons and/or solids produced from the insitu heat treatment process. Compositions that cause clogging may beformed during heating of the in situ heat treatment process liquid. Thecompositions may adhere to parts of the equipment and inhibit the flowof the liquid stream through processing units.

Solids that cause clogging may include, but are not limited to,organometallic compounds, inorganic compounds, minerals, mineralcompounds, cenospheres, coke, semi-soot, and/or mixtures thereof. Thesolids may have a particle size such that conventional filtration maynot remove the solids from the liquid stream. Hydrocarbons that causeclogging may include, but are not limited to, hydrocarbons that containheteroatoms, aromatic hydrocarbons, cyclic hydrocarbons, cyclicdi-olefins, and/or acyclic di-olefins. In some embodiments, solidsand/or hydrocarbons present in the in situ heat treatment process liquidthat cause clogging are partially soluble or insoluble in the situ heattreatment process liquid. In some embodiments, conventional filtrationof the liquid stream prior to or during heating is insufficient and/orineffective for removal of all or some of the compositions that clogprocess equipment.

In some embodiments, clogging compositions are at least partiallyremoved from the liquid stream by washing and/or desalting the liquidstream. In some embodiments, clogging of process equipment is inhibitedby filtering at least a portion of the liquid stream through ananofiltration system. In some embodiments, clogging of processequipment is inhibited by hydrotreating at least a portion of the liquidstream. In some embodiments, at least a portion the liquid stream isnanofiltered and then hydrotreated to remove composition that may clogand/or foul process equipment. The hydrotreated and/or nanofilteredliquid stream may be further processed to produce commercial products.In some embodiments, anti-fouling additives are added to the liquidstream to inhibit clogging of process equipment. Anti-fouling additivesare described in U.S. Pat. Nos. 5,648,305 to Mansfield et al.; 5,282,957to Wright et al.; 5,173,213 to Miller et al.; 4,840,720 to Reid;4,810,397 to Dvoracek; and 4,551,226 to Fern, all of which areincorporated by reference herein. Examples of commercially availableadditives include, but are not limited to, Chimec RO 303 Chimec RO 304,Chimec RO 305, Chimec RO 306, Chimec RO 307, Chimec RO 308, (availablefrom Chimec, Rome, Italy), GE-Betz Thermal Flow 7R29 GE-Betz ProChem3F28, Ge Betz ProChem 3F18 (available from GE Water and ProcessTechnologies, Trevose, Pa., U.S.A.).

FIGS. 5 and 5A depict schematic representations of an embodiment of asystem for producing crude products and/or commercial products from thein situ heat treatment process liquid stream and/or the in situ heattreatment process gas stream. Formation fluid 320 enters fluidseparation unit 322 and is separated into in situ heat treatment processliquid stream 324, in situ heat treatment process gas 240 and aqueousstream 326. In some embodiments, fluid separation unit 322 includes aquench zone. As produced formation fluid enters the quench zone,quenching fluid such as water, nonpotable water and/or other componentsmay be added to the formation fluid to quench and/or cool the formationfluid to a temperature suitable for handling in downstream processingequipment. Quenching the formation fluid may inhibit formation ofcompounds that contribute to physical and/or chemical instability of thefluid (for example, inhibit formation of compounds that may precipitatefrom solution, contribute to corrosion, and/or fouling of downstreamequipment and/or piping). The quenching fluid may be introduced into theformation fluid as a spray and/or a liquid stream. In some embodiments,the formation fluid is introduced into the quenching fluid. In someembodiments, the formation fluid is cooled by passing the fluid througha heat exchanger to remove some heat from the formation fluid. Thequench fluid may be added to the cooled formation fluid when thetemperature of the formation fluid is near or at the dew point of thequench fluid. Quenching the formation fluid near or at the dew point ofthe quench fluid may enhance solubilization of salts that may causechemical and/or physical instability of the quenched fluid (for example,ammonium salts). In some embodiments, an amount of water used in thequench is minimal so that salts of inorganic compounds and/or othercomponents do not separate from the mixture. In separation unit 322, atleast a portion of the quench fluid may be separated from the quenchmixture and recycled to the quench zone with a minimal amount oftreatment. Heat produced from the quench may be captured and used inother facilities. In some embodiments, vapor may be produced during thequench. The produced vapor may be sent to gas separation unit 328 and/orsent to other facilities for processing.

In situ heat treatment process gas 240 may enter gas separation unit 328to separate gas hydrocarbon stream 330 from the in situ heat treatmentprocess gas. The gas separation unit is, in some embodiments, arectified adsorption and high pressure fractionation unit. Gashydrocarbon stream 330 includes hydrocarbons having a carbon number ofat least 3.

In situ heat treatment process liquid stream 324 enters liquidseparation unit 332. In some embodiments, liquid separation unit 332 isnot necessary. In liquid separation unit 332, separation of in situ heattreatment process liquid stream 324 produces gas hydrocarbon stream 336and salty process liquid stream 338. Gas hydrocarbon stream 336 mayinclude hydrocarbons having a carbon number of at most 5. A portion ofgas hydrocarbon stream 336 may be combined with gas hydrocarbon stream330. Salty process liquid stream 338 may be processed through desaltingunit 340 to form liquid stream 334. Desalting unit 340 removes mineralsalts and/or water from salty process liquid stream 338 using knowndesalting and water removal methods. In certain embodiments, desaltingunit 340 is upstream of liquid separation unit 332.

Liquid stream 334 includes, but is not limited to, hydrocarbons having acarbon number of at least 5 and/or hydrocarbon containing heteroatoms(for example, hydrocarbons containing nitrogen, oxygen, sulfur, andphosphorus). Liquid stream 334 may include at least 0.001 g, at least0.005 g, or at least 0.01 g of hydrocarbons with a boiling rangedistribution between about 95° C. and about 200° C. at 0.101 MPa; atleast 0.01 g, at least 0.005 g, or at least 0.001 g of hydrocarbons witha boiling range distribution between about 200° C. and about 300° C. at0.101 MPa; at least 0.001 g, at least 0.005 g, or at least 0.01 g ofhydrocarbons with a boiling range distribution between about 300° C. andabout 400° C. at 0.101 MPa; and at least 0.001 g, at least 0.005 g, orat least 0.01 g of hydrocarbons with a boiling range distributionbetween 400° C. and 650° C. at 0.101 MPa. In some embodiments, liquidstream 334 contains at most 10% by weight water, at most 5% by weightwater, at most 1% by weight water, or at most 0.1% by weight water.

In some embodiments, the separated liquid stream may have a boilingrange distribution between about 50° C. and about 350° C., between about60° C. and 340° C., between about 70° C. and 330° C. or between about80° C. and 320° C. In some embodiments, the separated liquid stream hasa boiling range distribution between 180° C. and 330° C.

In some embodiments, at least 50%, at least 70%, or at least 90% byweight of the total hydrocarbons in the separated liquid stream have acarbon number from 8 to 13. The separated liquid stream may have fromabout 50% to about 100%, about 60% to about 95%, about 70% to about 90%,or about 75% to 85% by weight of liquid stream may have a carbon numberdistribution from 8 to 13. At least 50% by weight of the totalhydrocarbon in the separated liquid stream may have a carbon number fromabout 9 to 12 or from 10 to 11.

In some embodiments, the separated liquid stream has at most 15%, atmost 10%, at most 5% by weight of naphthenes; at least 70%, at least80%, or at least 90% by weight total paraffins; at most 5%, at most 3%,or at most 1% by weight olefins; and at most 30%, at most 20%, or atmost 10% by weight aromatics.

In some embodiments, the separated liquid stream has a nitrogen compoundcontent of at least 0.01%, at least 0.1% or at least 0.4% by weightnitrogen compound. The separated liquid stream may have a sulfurcompound content of at least 0.01%, at least 0.5% or at least 1% byweight sulfur compound.

After exiting desalting unit 340, liquid stream 334 enters filtrationsystem 342. In some embodiments, filtration system 342 is connected tothe outlet of the desalting unit. Filtration system 342 separates atleast a portion of the clogging compounds from liquid stream 334. Insome embodiments, filtration system 342 is skid mounted. Skid mountingfiltration system 342 may allow the filtration system to be moved fromone processing unit to another. In some embodiments, filtration system342 includes one or more membrane separators, for example, one or morenanofiltration membranes or one or more reserse osmosis membranes.

The membrane may be a ceramic membrane and/or a polymeric membrane. Theceramic membrane may be a ceramic membrane having a molecular weight cutoff of at most 2000 Daltons (Da), at most 1000 Da, or at most 500 Da.Ceramic membranes do not have to swell in order to work under optimalconditions to remove the desired materials from a substrate (forexample, clogging compositions from the liquid stream). In addition,ceramic membranes may be used at elevated temperatures. Examples ofceramic membranes include, but are not limited to, mesoporous titania,mesoporous gamma-alumina, mesoporous zirconia, mesoporous silica, andcombinations thereof.

The polymeric membrane includes a top layer made of a dense membrane anda base layer (support) made of a porous membrane. The polymeric membranemay be arranged to allow the liquid stream (permeate) to flow firstthrough the dense membrane top layer and then through the base layer sothat the pressure difference over the membrane pushes the top layer ontothe base layer. The polymeric membrane is an organophilic or ahydrophobic membrane so that water present in the liquid stream isretained or substantially retained in the retentate.

The dense membrane layer may separate at least a portion of orsubstantially all of the clogging compositions from liquid stream 334.In some embodiments, the dense polymeric membrane has properties suchthat liquid stream 334 passes through the membrane by dissolving in anddiffusing through its structure. At least a portion of the cloggingparticles may not dissolve and/or diffuse through the dense membrane,thus they are removed. The clogging particles may not dissolve and/ordiffuse through the dense membrane because of the complex structure ofthe clogging particles and/or their high molecular weight. The densemembrane layer may include a cross-linked structure as described in WO96/27430 to Schmidt et al., which is incorporated by reference herein. Athickness of the dense membrane layer may range from a 1 micrometer to15 micrometers, from 2 micrometers to 10 micrometers, or from 3micrometers to 5 micrometers.

The dense membrane may be made from polysiloxane, poly-di-methylsiloxane, poly-octyl-methyl siloxane, polyimide, polyaramide,poly-tri-methyl silyl propyne, or mixtures thereof. Porous base layersmay be made of materials that provide mechanical strength to themembrane and may be any porous membrane used for ultra filtration,nanofiltration, or reverse osmosis. Examples of such materials arepolyacrylonitrile, polyamideimide in combination with titanium oxide,polyetherimide, polyvinylidenedifluoroide, polytetrafluoroethylene orcombinations thereof.

During separation of clogging compositions from liquid stream 334, thepressure difference across the membrane may range from about 0.5 MPa toabout 6 MPa, from about 1 MPa to about 5 MPa, or from about 2 MPa toabout 4 MPa. A temperature of separation may range from the pour pointof the liquid stream up to 100° C., from about −20° C. to about 100° C.,from about 10° C. to about 90° C., or from about 20° C. to about 85° C.During continuous operation, the permeate flux rate may be at most 50%of the initial flux, at most 70% of the initial flux, or at most 90% ofthe initial flux. A weight recovery of the permeate on feed may rangefrom about 50% by weight to 97% by weight, from about 60% by weight to90% by weight, or from about 70% by weight to 80% by weight.

Filtration system 342 may include one or more membrane separators. Themembrane separators may include one or more membrane modules. When twoor more membrane separators are used, they may be arranged in a parallelconfiguration to allow feed (retentate) from a first membrane separatorto flow into a second membrane separator. Examples of membrane modulesinclude, but are not limited to, spirally wound modules, plate and framemodules, hollow fibers, and tubular modules. Membrane modules aredescribed in Encyclopedia of Chemical Engineering, 4th Ed., 1995, JohnWiley & Sons Inc., Vol. 16, pages 158-164. Examples of spirally woundmodules are described in, for example, WO/2006/040307 to Boestert etal., U.S. Pat. No. 5,102,551 to Pasternak; U.S. Pat. No. 5,093,002 toPasternak; U.S. Pat. No. 5,275,726 to Feimer et al.; U.S. Pat. No.5,458,774 to Mannapperuma; and U.S. Pat. No. 5,150,118 to Finkle et al,all of which are incorporated by reference herein.

In some embodiments, a spirally wound module is used when a densemembrane is used in filtration system 342. A spirally wound module mayinclude a membrane assembly of two membrane sheets between which apermeate spacer sheet is sandwiched, and which membrane assembly issealed at three sides. The fourth side is connected to a permeate outletconduit such that the area between the membranes in fluid communicationwith the interior of the conduit. On top of one of the membranes a feedspacer sheet is arranged, and the assembly with feed spacer sheet isrolled up around the permeate outlet conduit, to form a substantiallycylindrical spirally wound membrane module. The feed spacer may have athickness of at least 0.6 mm, at least 1 mm, or at least 3 mm to allowsufficient membrane surface to be packed into a spirally wound module.In some embodiments, the feed spacer is a woven feed spacer. Duringoperation, a feed mixture may be passed from one end of the cylindricalmodule between the membrane assemblies along the feed spacer sheetsandwiched between feed sides of the membranes. Part of the feed mixturepasses through either one of the membrane sheets to the permeate side.The resulting permeate flows along the permeate spacer sheet into thepermeate outlet conduit.

In some embodiments, the membrane separation is a continuous process.Liquid stream 334 passes over the membrane due to a pressure differenceto obtain a filtered liquid stream 344 (permeate) and/or recycle liquidstream 346 (retentate). In some embodiments, filtered liquid stream 344may have reduced concentrations of compositions and/or particles thatcause clogging in downstream processing systems. Continuous recycling ofrecycle liquid stream 346 through nanofiltration system can increase theproduction of filtered liquid stream 344 to as much as 95% of theoriginal volume of liquid stream 334. Recycle liquid stream 346 may becontinuously recycled through a spirally wound membrane module for atleast 10 hours, for at least one day, or for at least one week withoutcleaning the feed side of the membrane. Upon completion of thefiltration, waste stream 348 (retentate) may include a highconcentration of compositions and/or particles that cause clogging.Waste stream 348 exits filtration system 342 and is transported to otherprocessing units such as, for example, a delayed coking unit and/or agasification unit.

Filtered liquid stream 344 may exit filtration system 342 and enter oneor more process units. Process units as described herein for theproduction of crude products and/or commercial products may be operatedat the following temperatures, pressures, hydrogen source flows, liquidstream flows, or combinations thereof, or operated otherwise as known inthe art. Temperatures range from about 200° C. to about 900° C., fromabout 300° C. to about 800° C., or from about 400° C. to about 700° C.Pressures range from about 0.1 MPa to about 20 MPa, from about 1 MPa toabout 12 MPa, from about 4 MPa to about 10 MPa, or from about 6 MPa toabout 8 MPa. Liquid hourly space velocities of the liquid stream rangefrom about 0.1 h-1 to about 30 h-1, from about 0.5 h-1 to about 25 h-1,from about 1 h-1 to about 20 h-1, from about 1.5 h-1 to about 15 h-1, orfrom about 2 h-1 to about 10 h-1.

In FIG. 5, filtered liquid stream 344 and hydrogen source 246 enterhydrotreating unit 350. In some embodiments, hydrogen source 246 may beadded to filtered liquid stream 344 before entering hydrotreating unit350. In some embodiments, sufficient hydrogen is present in liquidstream 334 and hydrogen source 246 is not needed. In hydrotreating unit350, contact of filtered liquid stream 344 with hydrogen source 246 inthe presence of one or more catalysts produces liquid stream 352.Hydrotreating unit 350 may be operated such that all or at least aportion of liquid stream 352 is changed sufficiently to removecompositions and/or inhibit formation of compositions that may clogequipment positioned downstream of the hydrotreating unit 350. Thecatalyst used in hydrotreating unit 350 may be a commercially availablecatalyst. In some embodiments, hydrotreating of liquid stream 334 is notnecessary.

In some embodiments, liquid stream 334 is contacted with hydrogen in thepresence of one or more catalysts to change one or more desiredproperties of the crude feed to meet transportation and/or refineryspecifications using known hydrodemetallation, hydrodesulfurization,hydrodenitrofication techniques. Other methods to change one or moredesired properties of the crude feed are described in U.S. PublishedPatent Applications Nos. 2005-0133414; 2006-0231465; and 2007-0000810 toBhan et al.; 2005-0133405 to Wellington et al.; and 2006-0289340 toBrownscombe et al., all of which are incorporated by reference herein.

In some embodiments, the hydrotreated liquid stream has a nitrogencompound content of at most 200 ppm by weight, at most 150 ppm, at most110 ppm, at most 50 ppm, or at most 10 ppm of nitrogen compounds. Theseparated liquid stream may have a sulfur compound content of at most100 ppm, at most 500 ppm, at most 300 ppm, at most 100 ppm, or at most10 ppm by weight of sulfur compounds.

In some embodiments, hydrotreating unit 350 is a selective hydrogenationunit. In hydrotreating unit 350, liquid stream 334 and/or filteredliquid stream 344 are selectively hydrogenated such that di-olefins arereduced to mono-olefins. For example, liquid stream 334 and/or filteredliquid stream 344 is contacted with hydrogen in the presence of a DN-200(Criterion Catalysts & Technologies, Houston Tex., U.S.A.) attemperatures ranging from 100° C. to 200° C. and total pressures of 0.1MPa to 40 MPa to produce liquid stream 352. In some embodiments,filtered liquid stream 344 is hydrotreated at a temperature ranging fromabout 190° C. and about 200° C. at a pressure of at least 6 MPa. Liquidstream 352 includes a reduced content of di-olefins and an increasedcontent of mono-olefins relative to the di-olefin and mono-olefincontent of liquid stream 334. The conversion of di-olefins tomono-olefins under these conditions is, in some embodiments, at least50%, at least 60%, at least 80% or at least 90%. Liquid stream 352 exitshydrotreating unit 350 and enters one or more processing unitspositioned downstream of hydrotreating unit 350. The units positioneddownstream of hydrotreating unit 350 may include distillation units,catalytic reforming units, hydrocracking units, hydrotreating units,hydrogenation units, hydrodesulfurization units, catalytic crackingunits, delayed coking units, gasification units, or combinationsthereof. In some embodiments, hydrotreating prior to fractionation isnot necessary. In some embodiments, liquid stream 352 may be severelyhydrotreated to remove undesired compounds from the liquid stream priorto fractionation. In certain embodiments, liquid stream 352 may befractionated and then produced streams may each be hydrotreated to meetindustry standards and/or transportation standards.

Liquid stream 352 may exit hydrotreating unit 350 and enterfractionation unit 354. In fractionation unit 354, liquid stream 352 maybe distilled to form one or more crude products. Crude products include,but are not limited to, C₃-C₅ hydrocarbon stream 356, naphtha stream358, kerosene stream 360, diesel stream 362, and bottoms stream 364.Fractionation unit 354 may be operated at atmospheric and/or undervacuum conditions.

As shown in FIG. 5A, fractionation unit 354 includes two or more zonesoperated at different temperatures and pressures. Operating the twozones at different temperatures and pressures may inhibit orsubstantially reduce fouling of fractionation columns, heat exchangersand/or other equipment associated with fractionation unit 354. Liquidstream 352 may enter first fractionation zone 2000. Fractionation zone2000 may be operated at a temperature ranging from about 50° C. to about350° C., or from about 100° C. to 325° C., or from about 150° C. to 300°C. at 0.101 MPa to separate compounds boiling above 350° from the liquidstream to produce one or more crude products including, but not limitedto, C3-C5 hydrocarbon stream 356 a, naphtha stream 358′, kerosene stream360′, and diesel stream 362′. Hydrocarbons having a boiling point above350° C. (for example bottoms stream 364′) may enter second fractionationzone 2002. Second fractionation zone 2002 may be operated attemperatures greater than 350° C. at 0.101 MPa to separate one or morecrude products, including but not limited to, C3-C5 hydrocarbon stream356 b′, naphtha stream 358″, kerosene stream 360″, diesel stream 362″,and bottoms stream 364″. In some embodiments, second fractionation zone2002 is operated under vacuum. Bottoms stream 364, bottoms stream 364′,and/or bottoms stream 364″ generally includes hydrocarbons having aboiling range distribution of at least 340° C. at 0.101 MPa. In someembodiments, bottoms stream 364 is vacuum gas oil. In other embodiments,bottoms stream 364 bottoms stream 364′, and/or bottoms stream 364″includes hydrocarbons with a boiling range distribution of at least 537°C. One or more of the crude products may be sold and/or furtherprocessed to gasoline or other commercial products. In certainembodiments, one or more of the crude products may be hydrotreated tomeet industry standards and/or transportation standards.

As shown in FIG. 6, hydrotreated liquid stream may be treated infractionation unit 354 to remove compounds boiling below 180° C. toproduce distilled stream 355. Distilled stream 355 may have a boilingrange distribution between about 140° C. and about 350° C., betweenabout 180° C. and about 330° C., or between about 190° C. and about 310°C. In some embodiments distilled stream 355 may be hydrotreated prior tofractionation to remove undesired compounds (for example, sulfur and/ornitrogen compounds). In certain embodiments, distilled stream 355 issent to a hydrotreating unit and hydrotreated to meet transportationstandards for metals, nitrogen compounds and/or sulfur compounds.

In some embodiments, at least 50%, at least 70%, or at least 90% byweight of the total hydrocarbons in distilled liquid stream 355 have acarbon number from 8 to 13. Distilled liquid stream 355 may have fromabout 50% to about 100%, about 60% to about 95%, about 70% to about 90%,or about 75% to 85% by weight may have a carbon number from 8 to 13. Atleast 50% by weight to the total hydrocarbon in distilled liquid stream355 may have a carbon number from about 9 to 12 or from 10 to 11.

In some embodiments, hydrotreated and distilled liquid stream 355 has atmost 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%,at least 80%, or at least 90% by weight total paraffins; at most 5%, atmost 3%, or at most 1% by weight olefins; and at most 25%, at most 20%,or at most 15% by weight aromatics.

In some embodiments, hydrotreated and distilled liquid stream 355 has anitrogen compound content of at most 200 ppm by weight, at most 150 ppm,at most 110 ppm, at most 50 ppm, at most 10 ppm, or at most 5 ppm ofnitrogen compounds. The hydrotreated and distilled liquid stream mayhave a sulfur content of at most 50 ppm, at most 30 ppm or at most 10ppm by weight sulfur compound.

In some embodiments, hydrotreated and/or distilled liquid stream 355 hasa wear scar diameter as measured by ASTM D5001, ranging from about 0.1mm to about 0.9 mm, from about 0.2 mm to about 0.8 mm, or from 0.3 mm toabout 0.7 mm. In some embodiments, hydrotreated and/or distilled liquidstream 355 has a wear scar diameter, as measured by ASTM D5001 of atmost 0.85 mm, at most 0.8 mm, at most 0.6 mm, at most 0.5 mm, or at most0.3 mm. A wear scar diameter, as determined by ASTM D5001, may indicatethe hydrotreated and/or distilled stream may have acceptable lubricationproperties for transportation fuel (for example, commercial aviationfuel, fuel for military purposes, JP-8 fuel, Jet A-1 fuel).

Hydrotreating to remove undesired compounds (for example, sulfurcompounds and nitrogen compounds) from the liquid stream may decreasethe liquid stream to be an effective lubricant (for example, lubricityproperties when used as a transportation fuel). In some embodiments,hydrotreated and/or distilled liquid stream 355 has a minimalconcentration and/or no detectable amounts of sulfur compounds. A lowsulfur, nonadditized hydrotreated and/or distilled liquid stream 355 mayhave acceptable lubricity properties (for example, an acceptable wearscar diameter as measured by ASTM D5001). For example, the hydrotreatedand distilled liquid stream may have a boiling range distribution fromabout 140° C. to about 260° C., a sulfur content of at most 30 ppm byweight, and a wear scar diameter of at most 0.85 mm.

In some embodiments, naphtha stream 358, kerosene stream 360, dieselstream 362, (shown in FIGS. 5 and 5A), and distilled liquid stream 355are evaluated to determine an amount, if any, of additives and/orhydrocarbons that may be added to prepare a fully formulatedtransportation fuel and/or lubricant. For example, a distilled streammade by the processes described herein was evaluated for use in militaryvehicles against Department of Defense standard MIL-DTL-83133E usingASTM test methods. The results of the test are listed in TABLE 1.

TABLE 1 MIL-DTL-83133E Standard ASTM Test Specification Test LiquidStream Min Max Method Total Acid Number,   0.007 0.015 D3242 mg KOH/gAromatics, % volume   11.4 25.0 D1319 Mercaptan Sulfur,   0.000 0.001D3227 % mass Total Sulfur, % mass   0.00 0.3 D4294 Distillation: D2887IBP, ° C.  180 report 10% recovered, ° C.  188 186 20% recovered, ° C. 191 Report 50% recovered, ° C.  199 Report 90% recovered, ° C.  215Report EP, ° C.  229 330 Residue, % volume   0.9 1.5 Loss, % volume  0.3 1.5 Flash point, ° C.   60 38 D56 Cetane Index   43.7 report D976(calculated) Freeze Point, ° C.  −55 −47 D5901 Viscosity @ −20° C.,  4.4 8 D445 cSt Viscosity @ −40° C.,   9.0 cSt Heat of Combustion 1864442.8 D3338 (calculated), BTU/lb Hydrogen Content,   14.0 13.4 D3343 %mass Smoke Point, mm   26 25.0 D1322 Copper Strip   1a D130 CorrosionThermal Stability @ 260° C.: Tube Deposit Rating   1 D3241 Change inPressure,   0 mm Hg Existent Gum,   1.4 D381 mg/100 mL Water Reaction  1 D1094 Conductivity, pS/m   6* D2624 Density @ 15° C.   0.801 0.7750.840 D1298 Lubricity (BOCLE),   <0.85 D5001 wear scar mm

To enhance the use of the streams produced from formation fluid,hydrocarbons produced during fractionation of the liquid stream andhydrocarbon gases produced during separating the process gas may becombined to form hydrocarbons having a higher carbon number. Theproduced hydrocarbon gas stream may include a level of olefinsacceptable for alkylation reactions.

In some embodiments, hydrotreated liquid streams and/or streams producedfrom fractions (for example, distillates and/or naphtha) are blendedwith the in situ heat treatment process liquid and/or formation fluid toproduce a blended fluid. The blended fluid may have enhanced physicalstability and chemical stability as compared to the formation fluid. Theblended fluid may have a reduced amount of reactive species (forexample, di-olefins, other olefins and/or compounds containing oxygen,sulfur and/or nitrogen) relative to the formation fluid. Thus, chemicalstability of the blended fluid is enhanced. The blended fluid maydecrease an amount of asphaltenes relative to the formation fluid. Thus,physical stability of the blended fluid is enhanced. The blended fluidmay be a more a fungible feed than the formation fluid and/or the liquidstream produced from an in situ heat treatment process. The blended feedmay be more suitable for transportation, for use in chemical processingunits and/or for use in refining units than formation fluid.

In some embodiments, a fluid produced by methods described herein froman oil shale formation may be blended with heavy oil/tar sands in situheat treatment process (IHTP) fluid. Since the oil shale liquid issubstantially paraffinic and the heavy oil/tar sands IHTP fluid issubstantially aromatic, the blended fluid exhibits enhanced stability.In certain embodiments, in situ heat treatment process fluid may beblended with bitumen to obtain a feed suitable for use in refiningunits. Blending of the IHTP fluid and/or bitumen with the produced fluidmay enhance the chemical and/or physical stability of the blendedproduct. Thus, the blend may be transported and/or distributed toprocessing units.

As shown in FIGS. 5, 5A, and 6, C3-C5 hydrocarbon stream 356 producedfrom fractionation unit 354 and hydrocarbon gas stream 330 enteralkylation unit 368. In alkylation unit 368, reaction of the olefins inhydrocarbon gas stream 330 (for example, propylene, butylenes, amylenes,or combinations thereof) with the iso-paraffins in C3-C5 hydrocarbonstream 356 produces hydrocarbon stream 370. In some embodiments, theolefin content in hydrocarbon gas stream 330 is acceptable and anadditional source of olefins is not needed. Hydrocarbon stream 370includes hydrocarbons having a carbon number of at least 4. Hydrocarbonshaving a carbon number of at least 4 include, but are not limited to,butanes, pentanes, hexanes, heptanes, and octanes. In certainembodiments, hydrocarbons produced from alkylation unit 368 have anoctane number greater than 70, greater than 80, or greater than 90. Insome embodiments, hydrocarbon stream 370 is suitable for use as gasolinewithout further processing.

In some embodiments, bottoms stream 364 may be hydrocracked to producenaphtha and/or other products. The resulting naphtha may, however, needreformation to alter the octane level so that the product may be soldcommercially as gasoline. Alternatively, bottoms stream 364 may betreated in a catalytic cracker to produce naphtha and/or feed for analkylation unit. In some embodiments, naphtha stream 358, kerosenestream 360, and diesel stream 362 have an imbalance of paraffinichydrocarbons, olefinic hydrocarbons, and/or aromatic hydrocarbons. Thestreams may not have a suitable quantity of olefins and/or aromatics foruse in commercial products. This imbalance may be changed by combiningat least a portion of the streams to form combined stream 366 which hasa boiling range distribution from about 38° C. to about 343° C.Catalytically cracking combined stream 366 may produce olefins and/orother streams suitable for use in an alkylation unit and/or otherprocessing units. In some embodiments, naphtha stream 358 ishydrocracked to produce olefins.

In FIG. 5 and FIG. 5A, combined stream 366 and bottoms stream 364 fromfractionation unit 354 enters catalytic cracking unit 372. In FIG. 5A,combined stream 366 may include all or portions of streams 358′, 360′,362′, 358″, 360″, 362″. Under controlled cracking conditions (forexample, controlled temperatures and pressures), catalytic cracking unit372 produces additional C3-C5 hydrocarbon stream 356′, gasolinehydrocarbons stream 374, and additional kerosene stream 360′.

Additional C3-C5 hydrocarbon stream 356′ may be sent to alkylation unit368, combined with C3-C5 hydrocarbon stream 356, and/or combined withhydrocarbon gas stream 330 to produce gasoline suitable for commercialsale. In some embodiments, the olefin content in hydrocarbon gas stream330 is acceptable and an additional source of olefins is not needed.

In some embodiments, an amount of the produced bottoms stream (forexample, VGO) is too low to sustain operation of a hydrocracking unit orcatalytic cracking unit and the concentration of olefins in the producedgas streams from a fractionation unit and/or a catalytic cracking unit(for example, from fractionation unit 354 and/or from catalytic crackingunit 372 in FIG. 5) may be too low to sustain operation of an alkylationunit. The naphtha produced from the fractionation unit may be treated toproduce olefins for further processing in, for example, an alkylationunit. Reformulated gasoline produced by conventional naphtha reformingprocesses may not meet commercial specifications such as, for example,California Air Resources Board mandates when liquid stream produced froman in situ heat treatment process liquid is used as a feed stream. Anamount of olefins in the naphtha may be saturated during conventionalhydrotreating prior to the reforming naphtha process. Thus, reforming ofall the hydrotreated naphtha may result in a higher than desiredaromatics content in the gasoline pool for reformulated gasoline. Theimbalance in the olefin and aromatic content in the reformed naphtha maybe changed by producing sufficient alkylate from an alkylation unit toproduce reformulated gasoline. Olefins (for example, propylene andbutylenes) generated from fractionation and/or cracking of the naphthamay be combined with isobutane to produce gasoline. In addition, it hasbeen found that catalytically cracking the naphtha and/or otherfractionated streams produced in a fractionating unit requiresadditional heat because of a reduced amount of coke production relativeto other feedstocks used in catalytic cracking units.

FIG. 7 depicts a schematic for treating liquid streams produced from anin situ heat treatment process stream to produce olefins and/or liquidstreams. Similar processes to produce middle distillate and olefins aredescribed in International Publication No. WO 2006/020547 and U.S.Patent Application Publication Nos. 2006-0191820 and 2006-0178546 to Moet al., all of which are incorporated by referenced herein. Liquidstream 376 enters catalytic cracking system 378. Liquid stream 376 mayinclude, but is not limited to, liquid stream 334, hydrotreated liquidstream 352, filtered liquid stream 344, naphtha stream 358, kerosenestream 360, diesel stream 362, and bottoms stream 364 from the systemdepicted in FIG. 5, any hydrocarbon stream having a boiling rangedistribution between 65° C. and 800° C., or mixtures thereof. In someembodiments, steam 272 enters catalytic cracking system 378 and mayatomize and/or lift liquid stream 376 to enhance contact of the liquidstream with the catalytic cracking catalyst. A ratio of steam to atomizeliquid stream 376 to feedstock may range from 0.01 to 2 by weight, orfrom 0.1 to 1 by weight.

In catalytic cracking system 378, liquid stream 376 is contacted with acatalytic cracking catalyst to produce one or more crude products. Thecatalytic cracking catalyst includes a selected catalytic crackingcatalyst, at least a portion of used regenerated cracking catalyststream 380, at least a portion of a regenerated cracking catalyst stream382, or a mixture thereof. Used regenerated cracking catalyst 380includes a regenerated cracking catalyst that has been used in secondcatalytic cracking system 384. Second catalytic cracking system 384 maybe used to crack hydrocarbons to produce olefins and/or other crudeproducts. Hydrocarbons provided to second catalytic cracking system 384may include C3-C5 hydrocarbons produced from the production wells,gasoline hydrocarbons, hydrowax, hydrocarbons produced fromFischer-Tropsch processes, biofuels, or combinations thereof. The use ofa mixture of different types of hydrocarbon feed to the second catalyticcracking system may enhance C3-C5 olefin production to meet the alkylatedemand. Thus, integration of the products with refinery processes may beenhanced. Second catalytic cracking system 384 may be a dense phaseunit, a fixed fluidized bed unit, a riser, a combination of the abovementioned units, or any unit or configuration of units known in the artfor cracking hydrocarbons.

Contact of the catalytic cracking catalyst and the liquid stream 376 incatalytic cracking system 378 produces a crude product and spentcracking catalyst. The crude product may include, but is not limited to,hydrocarbons having a boiling point distribution that is less than theboiling point distribution of liquid stream 376, a portion of liquidstream 376, or mixtures thereof. The crude product and spent catalystenters separation system 386. Separation system 386 may include, forexample, a distillation unit, a stripper, a filtration system, acentrifuge, or any device known in the art capable of separating thecrude product from the spent catalyst.

Separated spent cracking catalyst stream 388 exits separation system 386and enters regeneration unit 390. In regeneration unit 390, spentcracking catalyst is contacted with oxygen source 392 (for example,oxygen and/or air) under carbon burning conditions to produceregenerated cracking catalyst stream 382 and combustion gases 394.Combustion gases may form as a by-product of the removal of carbonand/or other impurities formed on the catalyst during the catalyticcracking process.

The temperature in regeneration unit 390 may range from about 621° C. toabout 760° C. or from about 677° C. to about 715° C. The pressure inregeneration unit 390 may range from atmospheric to about 0.345 MPa orfrom about 0.034 to about 0.345 MPa. The residence time of the separatedspent cracking catalyst in regeneration unit 390 ranges from about 1 toabout 6 minutes or from or about 2 to about 4 minutes. The coke contenton the regenerated cracking catalyst is less than the coke content onthe separated spent cracking catalyst. Such coke content is less than0.5% by weight, with the weight percent being based on the weight of theregenerated cracking catalyst excluding the weight of the coke content.The coke content of the regenerated cracking catalyst may range from0.01% by weight to 0.5% by weight, 0.05% by weight to 0.3% by weight, or0.1% by weight to 0.2% by weight.

In some embodiments, regenerated cracking catalyst stream 382 may bedivided into two streams with at least a portion of regenerated crackingcatalyst stream 382′ exiting regeneration unit 390 and entering secondcatalytic cracking system 384. At least another portion of regeneratedcracking catalyst stream 382 exits regenerator 390 and enters catalyticcracking system 378. The relative amount of the used regeneratedcracking catalyst to the regenerated cracking catalyst is adjusted toprovide for the desired cracking conditions within catalytic crackingsystem 378. Adjusting the ratio of used regenerated cracking catalyst toregenerated cracking catalyst may assist in the control of the crackingconditions in catalytic cracking system 378. A weight ratio of the usedregenerated cracking catalyst to the regenerated cracking catalyst mayrange from 0.1:1 to 100:1, from 0.5:1 to 20:1, or from 1:1 to 10:1. Fora system operated at steady state, the weight ratio of used regeneratedcracking catalyst to regenerated cracking catalyst approximates theweight ratio of the portion of regenerated cracking catalyst passing tothe second catalytic cracking system 384 to the remaining portion ofregenerated cracking catalyst that is mixed with liquid stream 376introduced into catalytic cracking system 378, and, thus, theaforementioned ranges are also applicable to such weight ratio.

Crude product 396 exits separation system 386 and enters liquidseparation unit 398. Liquid separation unit 398 may be any system knownto those skilled in the art for recovering and separating the crudeproduct into product streams such as, for example, gas stream 336′,gasoline hydrocarbons stream 400, cycle oil stream 402, and bottomstream 404. In some embodiments, bottom stream 404 is recycled tocatalytic cracking system 378. Liquid separation unit 398 may includecomponents and/or units such as, for example, absorbers and strippers,fractionators, compressors and separators, or any combination of knownsystems for providing recovery and separation of products from the crudeproduct. In some embodiments, at least a portion of light cycle oilstream 402 exits liquid separation unit 398 and enters second catalyticcracking system 384. In some embodiments, none of the light cycle oilstream is sent to the second catalytic cracking system. In someembodiments, at least a portion of gasoline hydrocarbons stream 400exits liquid separation unit 398 and enters second catalytic crackingsystem 384. In some embodiments, none of the gasoline hydrocarbonsstream is sent to the second catalytic cracking system. In someembodiments, gasoline hydrocarbons stream 400 is suitable for saleand/or for use in other processes.

At least a portion of gas oil hydrocarbon stream 406 (for example,vacuum gas oil) and/or portions of gasoline hydrocarbons stream 400 andat least a portion of light cycle oil stream 402 are sent to catalyticcracking system 384. The streams are catalytically cracked in thepresence of steam 272′ to produce crude olefin stream 408. Crude olefinstream 408 may include hydrocarbons having a carbon number of at least2. In some embodiments, crude olefin stream 408 contains at least 30% byweight C₂-C₅ olefins, at least 40% by weight C₂-C₅ olefins, at least 50%by weight C₂-C₅ olefins, at least 70% by weight C₂-C₅ olefins, or atleast 90% by weight C₂-C₅ olefins. Recycling gasoline hydrocarbonsstream 400 into second catalytic cracking system 384 may provide for anadditional conversion across the overall process system of gas oilhydrocarbon stream 406 to C₂-C₅ olefins.

In some embodiments, second catalytic cracking system 384 includes anintermediate reaction zone and a stripping zone that are in fluidcommunication with each other, with the stripping zone located below theintermediate reaction zone. To provide for a high steam velocity withinthe stripping zone, compared to the velocity within the intermediatereaction zone, the cross-sectional area of the stripping zone is lessthan the cross-sectional area of the intermediate reaction zone. Theratio of the stripping zone cross-sectional area to the intermediatereaction zone cross sectional area may range from 0.1:1 to 0.9:1; from0.2:1 to 0.8:1; or from 0.3:1 to 0.7:1.

In some embodiments, the geometry of the second catalytic crackingsystem is such that it is generally cylindrical. The length-to-diameterratio of the stripping zone of the catalytic cracking system providesfor the desired high steam velocity within the stripping zone andprovides enough contact time within the stripping zone for the desiredstripping of the used regenerated catalyst that is to be removed fromthe second catalytic cracking system. Thus, the length-to-diameter ratioof the stripping zone may range of from 1:1 to 25:1; from 2:1 to 15:1;or from 3:1 to 10:1.

In some embodiments, second catalytic cracking system 384 is operated orcontrolled independently from the operation or control of catalyticcracking system 378. Independent operation or control of secondcatalytic cracking system 384 may improve overall conversion of thegasoline hydrocarbons into the desired products such as ethylene,propylene and butylenes. With the independent operation of secondcatalytic cracking system 384, the severity of catalytic cracking unit378 may be reduced to optimize the yield of C2-C5 olefins. A temperaturein second catalytic cracking system 384 may range from about 482° C.(900° F.) to about 871° C. (1600° F.), from about 510° C. (950° F.) toabout 871° C. (1600° F.), or from about 538° C. (1000° F.) to about 732°C. (1350° F.). The operating pressure of second catalytic crackingsystem 384 may range from atmospheric to about 0.345 MPa (50 psig) orfrom about 0.034 to 0.345 MPa (5 to 50 psig).

Addition of steam 272′ into second catalytic cracking system 384 mayassist in the operational control of the second catalytic cracking unit.In some embodiments, steam is not necessary. In some embodiments, theuse of the steam for a given gasoline hydrocarbon conversion across theprocess system, and in the cracking of the gasoline hydrocarbons, mayprovide for an improved selectivity toward C2-C5 olefin yield with anincrease in propylene and butylenes yield relative to other catalyticcracking processes. A weight ratio of steam to gasoline hydrocarbonsintroduced into second catalytic cracking system 384 may be up to orabout 15:1; from 0.1:1 to 10:1; from 0.2:1 to 9:1; or from 0.5:1 to 8:1.

Crude olefin stream 408 enters olefin separation system 410. Olefinseparation system 410 can be any system known to those skilled in theart for recovering and separating the crude olefin stream 408 into C2-C5olefin product streams (for example, ethylene product stream 412,propylene product stream 414, and butylenes products stream 416). Olefinseparation system 410 may include such systems as absorbers andstrippers, fractionators, compressors and separators, or any combinationof known systems or equipment providing for the recovery and separationof C2-C5 olefin products from fluid stream 408. In some embodiments,olefin streams 412, 414, 416 enter alkylation unit 368 to generatehydrocarbon stream 370. In some embodiments, hydrocarbon stream 370 hasan octane number of at least 70, at least 80, or at least 90. In someembodiments, all or portions of one or more of streams 412, 414, 416 aretransported to other processing units, such as polymerization units, foruse as feedstocks.

In some embodiments, the crude product from the catalytic crackingsystem and the crude olefin stream from second catalytic cracking systemmay be combined. The combined stream may enter a single separation unit(for example, a combination of liquid separation system 398 and olefinseparation system 410).

In FIG. 7, used cracking catalyst stream 380 exits second catalyticcracking system 384 and enters catalytic cracking system 378. Catalystin used cracking catalyst stream 380 may include a slightly higherconcentration of carbon than the concentration of carbon that is on thecatalyst in regenerated cracking catalyst 382. A high concentration ofcarbon on the catalyst may partially deactivate the catalytic crackingcatalysts which provides for an enhanced yield of olefins from thecatalytic cracking system 378. Coke content of the used regeneratedcatalyst may be at least 0.1% by weight or at least 0.5% by weight. Thecoke content of the used regenerated catalyst may range from about 0.1%by weight to about 1% by weight or from about 0.1% by weight to about0.6% by weight.

The catalytic cracking catalyst used in catalytic cracking system 378and second catalytic cracking system 384 may be any fluidizable crackingcatalyst known in the art. The fluidizable cracking catalyst may includea molecular sieve having cracking activity dispersed in a porous,inorganic refractory oxide matrix or binder. “Molecular sieve” refers toany material capable of separating atoms or molecules based on theirrespective dimensions. Molecular sieves suitable for use as a componentof the cracking catalyst include pillared clays, delaminated clays, andcrystalline aluminosilicates. In some embodiments, the cracking catalystcontains a crystalline aluminosilicate. Examples of suchaluminosilicates include Y zeolites, ultrastable Y zeolites, X zeolites,zeolite beta, zeolite L, offretite, mordenite, faujasite, and zeoliteomega. In some embodiments, crystalline aluminosilicates for use in thecracking catalyst are X and/or Y zeolites. U.S. Pat. No. 3,130,007 toBreck describes Y-type zeolites.

The stability and/or acidity of a zeolite used as a component of thecracking catalyst may be increased by exchanging the zeolite withhydrogen ions, ammonium ions, polyvalent metal cations, such as rareearth-containing cations, magnesium cations or calcium cations, or acombination of hydrogen ions, ammonium ions and polyvalent metalcations. The sodium content may be lowered until it is at most 0.8% byweight, at most 0.5% by weight and at most 0.3% by weight, calculated asNa₂O. Methods of carrying out the ion exchange are well known in theart.

The zeolite or other molecular sieve component of the cracking catalystis combined with a porous, inorganic refractory oxide matrix, or binderto form a finished catalyst prior to use. The refractory oxide componentin the finished catalyst may be silica-alumina, silica, alumina, naturalor synthetic clays, pillared or delaminated clays, mixtures of one ormore of these components, and the like. In some embodiments, theinorganic refractory oxide matrix includes a mixture of silica-aluminaand clay such as kaolin, hectorite, sepiolite, and attapulgite. Afinished catalyst may contain between about 5% by weight and about 40%by weight zeolite or other molecular sieve and greater than about 20weight percent inorganic refractory oxide. In some embodiments, thefinished catalyst may contain between about 10% and about 35% by weightzeolite or other molecular sieve, between about 10% and about 30% byweight inorganic refractory oxide, and between about 30% and about 70%by weight clay.

The crystalline aluminosilicate or other molecular sieve component ofthe cracking catalyst may be combined with the porous, inorganicrefractory oxide component or a precursor thereof by any suitabletechnique known in the art including mixing, mulling, blending orhomogenization. Examples of precursors that may be used include, but arenot limited to, alumina, alumina sols, silica sols, zirconia, aluminahydrogels, polyoxycations of aluminum and zirconium, and peptizedalumina. In some embodiments, the zeolite is combined with analumino-silicate gel or sol or other inorganic, refractory oxidecomponent, and the resultant mixture is spray dried to produce finishedcatalyst particles normally ranging in diameter between about 40micrometers and about 80 micrometers. In some embodiments, the zeoliteor other molecular sieve may be mulled or otherwise mixed with therefractory oxide component or precursor thereof, extruded and thenground into the desired particle size range. The finished catalyst mayhave an average bulk density between about 0.30 and about 0.90 gram percubic centimeter and a pore volume between about 0.10 and about 0.90cubic centimeter per gram.

In some embodiments, a ZSM-5 additive may be introduced into theintermediate cracking reactor of second catalytic cracking system 384.When a ZSM-5 additive is used along with the selected cracking catalystin the intermediate cracking reactor, a yield of the lower olefins suchas propylene and butylenes is enhanced. An amount of ZSM-5 ranges fromat most 30% by weight, at most 20% by weight, or at most 18% by weightof the regenerated catalyst being introduced into second catalyticcracking system 384. An amount of ZSM-5 additive is introduced intosecond catalytic cracking system 384 may range from 1% to 30% by weight,3% to 20% by weight, or 5% to 18% by weight of the regenerated crackingcatalyst being introduced into second catalytic cracking system 384.

The ZSM-5 additive is a molecular sieve additive selected from thefamily of medium pore size crystalline aluminosilicates or zeolites.Molecular sieves that can be used as the ZSM-5 additive include, but arenot limited to, medium pore zeolites as described in “Atlas of ZeoliteStructure Types,” Eds. W. H. Meier and D. H. Olson,Butterworth-Heineman, Third Edition, 1992. The medium pore size zeolitesgenerally have a pore size from about 0.5 μm, to about 0.7 nm andinclude, for example, MFI, MFS, MEL, MTW, EUO, MTT, HEU, FER, and TONstructure type zeolites (IUPAC Commission of Zeolite Nomenclature).Non-limiting examples of such medium pore size zeolites, includingZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-34, ZSM-35, ZSM-38, ZSM-48, ZSM-50,silicalite, and silicalite 2. ZSM-5, are described in U.S. Pat. Nos.3,702,886 to Argauer et al. and 3,770,614 to Graven, both of which areincorporated by reference herein.

ZSM-11 is described in U.S. Pat. No. 3,709,979 to Chu; ZSM-12 in U.S.Pat. No. 3,832,449 to Rosinski et al.; ZSM-21 and ZSM-38 in U.S. Pat.No. 3,948,758 to Bonacci et al.; ZSM-23 in U.S. Pat. No. 4,076,842 toPlank et al.; and ZSM-35 in U.S. Pat. No. 4,016,245 to Plank et al., allof which are incorporated by reference herein. Other suitable molecularsieves include the silicoaluminophosphates (SAPO), such as SAPO-4 andSAPO-11 which is described in U.S. Pat. No. 4,440,871 to Lok et al.;chromosilicates; gallium silicates, iron silicates; aluminum phosphates(ALPO), such as ALPO-11 described in U.S. Pat. No. 4,310,440 to Wilsonet al.; titanium aluminosilicates (TASO), such as TASO-45 described inU.S. Pat. No. 4,686,029 to Pellet et al.; boron silicates, described inU.S. Pat. No. 4,254,297 Frenken et al.; titanium aluminophosphates(TAPO), such as TAPO-11 described in U.S. Pat. No. 4,500,651 to Lok etal.; and iron aluminosilicates, all of which are incorporated byreference herein.

U.S. Pat. No. 4,368,114 to Chester et al., which is incorporated byreference herein, describes in detail the class of zeolites that can besuitable ZSM-5 additives. The ZSM-5 additive may be held together with acatalytically inactive inorganic oxide matrix component, in accordancewith conventional methods.

In some embodiments, liquid streams produced from a heat treatmentconversion process (for example liquid stream 334, and/or bottoms stream364) and/or residue produced from units described in FIGS. 5 and 7 maybe used as an energy source. Liquid stream 334 and/or the residue may begasified to produce gases (for example, hydrogen and/or carbon monoxide)which are burned (for example, burned in a turbine) and/or injected intoa subsurface formation (for example, injection of produced carbondioxide into a subsurface formation). In some embodiments, the liquidstreams, formation fluids, and/or residue are heated in the presence ofsteam and/or a catalyst to produce hydrogen, carbon dioxide and/orcarbon monoxide. In certain embodiments, the residue is de-asphalted toproduce asphalt. The asphalt may be gasified. U.S. Pat. Nos. 6,916,562to Gosselink et al.; and 4,233,187 to Atwood et al.; and U.S. PatentApplication Publication No. 2006-0289340 to Brownscombe et al. describedmethods to gasify hydrocarbon compounds.

In some embodiments, additives and/or heavier hydrocarbons may becombined with the processed liquid stream to prepare a finished fueland/or lubricant to meet requirements for use in various industrial,commercial, and/or military applications (for example, fuel and/orlubricants for turbines, diesel trucks, aircraft, military vehicles).Examples of additives include, but are not limited to, corrosioninhibitors, lubricity improvers, static dissipate additives, fuel systemicing inhibitors, antioxidants, detergents, surfactants, frictionmodifiers, or mixtures thereof.

In some embodiments, transportation fuel made from hydrocarbons obtainedfrom an in situ heat treatment process and processed as described hereinis suitable for use as fuel for aircraft and diesel fuel consumingvehicles and equipment. For example, the transportation fuel may be usedin commercial utility cargo vehicles, high mobility multipurpose wheeledvehicles, military recovery vehicles, tanks, armored personnel carriers,and multi-ton diesel trucks. The transportation fuel may have a boilingrange distribution between about 180° C. and about 330° C. as determinedby ASTM D2887, an API gravity between 37 and 51 as determined by ASTMD1298, a freezing point of at most −47° C. as determined by ASTM D5901;a viscosity of at most 8.0 mm²/s at −20° C. as determined by ASTM D445,a hydrogen content of at least 23.4% by weight as determined by ASTMD3343, an aromatics content of at most 25% by volume as determined byASTM D1319, sulfur content of at most 0.3% by weight as determined byASTM D4294, a net heat of combustion of at least 42.8 MJ/kg asdetermined by ASTM D3338; and thermal oxidation stability properties of:a heat tube deposit of at most 3 and a change in pressure drop of atmost 25 mm Hg as determined by ASTM D3241.

During some in situ heat treatment processes, ammonia may be information fluid produced from the formation. Produced ammonia may beused for a number of purposes. In some embodiments, the ammonia or aportion of the ammonia may be used to produce hydrogen. In someembodiments, the Haber-Bosch process may be used to produce hydrogen.Ammonia may produce hydrogen and nitrogen according to the followingequilibrium reaction:

N₂+3H₂⇄2NH₃  (EQN. 1)

The reaction may be a high temperature, high pressure, catalyzedreaction. The temperature may be from about 300° C. to about 800° C. Thepressure may be from about 80 bars to about 220 bars. The catalyst maybe composed substantially of iron. The total amount of hydrogen producedmay be increased by shifting the equilibrium towards hydrogen andnitrogen production. Equilibrium may be shifted to produce more nitrogenand hydrogen by removing nitrogen and/or hydrogen as they are produced.

Many wells are needed for treating the hydrocarbon formation using thein situ heat treatment process. In some embodiments, vertical orsubstantially vertical wells are formed in the formation. In someembodiments, horizontal or U-shaped wells are formed in the formation.In some embodiments, combinations of horizontal and vertical wells areformed in the formation.

A manufacturing approach for the formation of wellbores in the formationmay be used due to the large number of wells that need to be formed forthe in situ heat treatment process. The manufacturing approach may beparticularly applicable for forming wells for in situ heat treatmentprocesses that utilize u-shaped wells or other types of wells that havelong non-vertically oriented sections. Surface openings for the wellsmay be positioned in lines running along one or two sides of thetreatment area. FIG. 8 depicts a schematic representation of anembodiment of a system for forming wellbores of an in situ heattreatment process.

The manufacturing approach for the formation of wellbores mayinclude: 1) delivering flat rolled steel to near site tube manufacturingplant that forms coiled tubulars and/or pipe for surface pipelines; 2)manufacturing large diameter coiled tubing that is tailored to therequired well length using electrical resistance welding (ERW), whereinthe coiled tubing has customized ends for the bottom hole assembly (BHA)and hang off at the wellhead; 3) deliver the coiled tubing to a drillingrig on a large diameter reel; 4) drill to total depth with coil and aretrievable bottom hole assembly; 5) at total depth, disengage the coiland hang the coil on the wellhead; 6) retrieve the BHA; 7) launch anexpansion cone to expand the coil against the formation; 8) return emptyspool to the tube manufacturing plant to accept a new length of coiledtubing; 9) move the gantry type drilling platform to the next welllocation; and 10) repeat.

In situ heat treatment process locations may be distant from establishedcities and transportation networks. Transporting formed pipe or coiledtubing for wellbores to the in situ process location may be untenabledue to the lengths and quantity of tubulars needed for the in situ heattreatment process. One or more tube manufacturing facilities 2004 may beformed at or near to the in situ heat treatment process location. Thetubular manufacturing facility may form plate steel into coiled tubing.The plate steel may be delivered to tube manufacturing facilities 2004by truck, train, ship or other transportation system. In someembodiments, different sections of the coiled tubing may be formed ofdifferent alloys. The tubular manufacturing facility may use ERW tolongitudinally weld the coiled tubing.

Tube manufacturing facilities 2004 may be able to produce tubing havingvarious diameters. Tube manufacturing facilities may initially be usedto produce coiled tubing for forming wellbores. The tube manufacturingfacilities may also be used to produce heater components, piping fortransporting formation fluid to surface facilities, and other piping andtubing needs for the in situ heat treatment process.

Tube manufacturing facilities 2004 may produce coiled tubing used toform wellbores in the formation. The coiled tubing may have a largediameter. The diameter of the coiled tubing may be from about 4 inchesto about 8 inches in diameter. In some embodiments, the diameter of thecoiled tubing is about 6 inches in diameter. The coiled tubing may beplaced on large diameter reels. Large diameter reels may be needed dueto the large diameter of the tubing. The diameter of the reel may befrom about 10 m to about 50 m. One reel may hold all of the tubingneeded for completing a single well to total depth.

In some embodiments, tube manufacturing facilities 2004 has the abilityto apply expandable zonal inflow profiler (EZIP) material to one or moresections of the tubing that the facility produces. The EZIP material maybe placed on portions of the tubing that are to be positioned near andnext to aquifers or high permeability layers in the formation. Whenactivated, the EZIP material forms a seal against the formation that mayserve to inhibit migration of formation fluid between different layers.The use of EZIP layers may inhibit saline formation fluid from mixingwith non-saline formation fluid.

The size of the reels used to hold the coiled tubing may prohibittransport of the reel using standard moving equipment and roads. Becausetube manufacturing facility 2004 is at or near the in situ heattreatment location, the equipment used to move the coiled tubing to thewell sites does not have to meet existing road transportationregulations and can be designed to move large reels of tubing. In someembodiments the equipment used to move the reels of tubing is similar tocargo gantries used to move shipping containers at ports and otherfacilities. In some embodiments, the gantries are wheeled units. In someembodiments, the coiled tubing may be moved using a rail system or othertransportation system.

The coiled tubing may be moved from the tubing manufacturing facility tothe well site using gantries 2006. Drilling gantry 2008 may be used atthe well site. Several drilling gantries 2008 may be used to formwellbores at different locations. Supply systems for drilling fluid orother needs may be coupled to drilling gantries 2008 from centralfacilities 2010.

Drilling gantry 2008 or other equipment may be used to set the conductorfor the well. Drilling gantry 2008 takes coiled tubing, passes thecoiled tubing through a straightener, and a BHA attached to the tubingis used to drill the wellbore to depth. In some embodiments, a compositecoil is positioned in the coiled tubing at tube manufacturing facility2004. The composite coil allows the wellbore to be formed without havingdrilling fluid flowing between the formation and the tubing. Thecomposite coil also allows the BHA to be retrieved from the wellbore.The composite coil may be pulled from the tubing after wellboreformation. The composite coil may be returned to the tubingmanufacturing facility to be placed in another length of coiled tubing.In some embodiments, the BHAs are not retrieved from the wellbores.

In some embodiments, drilling gantry 2008 takes the reel of coiledtubing from gantry 2006. In some embodiments, gantry 2006 is coupled todrilling gantry 2008 during the formation of the wellbore. For example,the coiled tubing may be fed from gantry 2006 to drilling gantry 2008,or the drilling gantry lifts the gantry to a feed position and thetubing is fed from the gantry to the drilling gantry.

The wellbore may be formed using the bottom hole assembly, coiled tubingand the drilling gantry. The BHA may be self-seeking to the destination.The BHA may form the opening at a fast rate. In some embodiments, theBHA forms the opening at a rate of about 100 m per hour.

After the wellbore is drilled to total depth, the tubing may besuspended from the wellhead. An expansion cone may be used to expand thetubular against the formation. In some embodiments, the drilling gantryis used to install a heater and/or other equipment in the wellbore.

When drilling gantry 2008 is finished at well site 2012, the drillinggantry may release gantry 2006 with the empty reel or return the emptyreel to the gantry. Gantry 2006 may take the empty reel back to tubemanufacturing facility 2004 to be loaded with another coiled tube.Gantries 2006 may move on looped path 2014 from tube manufacturingfacility 2004 to well sites 2012 and back to the tube manufacturingfacility.

Drilling gantry 2008 may be moved to the next well site. Globalpositioning satellite information, lasers and/or other information maybe used to position the drilling gantry at desired locations. Additionalwellbores may be formed until all of the wellbores for the in situ heattreatment process are formed.

In some embodiments, positioning and/or tracking system may be utilizedto track gantries 2006, drilling gantries 2008, coiled tubing reels andother equipment and materials used to develop the in situ heat treatmentlocation. Tracking systems may include bar code tracking systems toensure equipment and materials arrive where and when needed.

Pieces of formation or rock may protrude or fall into the wellbore dueto various failures including rock breakage or plastic deformationduring and/or after wellbore formation. Protrusions may interfere withdrill string movement and/or the flow of drilling fluids. Protrusionsmay prevent running tubulars into the wellbore after the drill stringhas been removed from the wellbore. Significant amounts of materialentering or protruding into the wellbore may cause wellbore integrityfailure and/or lead to the drill string becoming stuck in the wellbore.Some causes of wellbore integrity failure may be in situ stresses andhigh pore pressures. Mud weight may be increased to hold back theformation and inhibit wellbore integrity failure during wellboreformation. When increasing the mud weight is not practical, the wellboremay be reamed.

Reaming the wellbore may be accomplished by moving the drill string upand down one joint while rotating and circulating. Picking the drillstring up can be difficult because of material protruding into theborehole above the bit or BHA (bottom hole assembly). Picking up thedrill string may be facilitated by placing upward facing cuttingstructures on the drill bit. Without upward facing cutting structures onthe drill bit, the rock protruding into the borehole above the drill bitmust be broken by grinding or crushing rather than by cutting. Grindingor crushing may induce additional wellbore failure.

Moving the drill string up and down may induce surging or pressurepulses that contribute to wellbore failure. Pressure surging orfluctuations may be aggravated or made worse by blockage of normaldrilling fluid flow by protrusions into the wellbore. Thus, attempts toclear the borehole of debris may cause even more debris to enter thewellbore.

When the wellbore fails further up the drill string than one joint fromthe drill bit, the drill string must be raised more than one joint.Lifting more than one joint in length may require that joints be removedfrom the drill string during lifting and placed back on the drill stringwhen lowered. Removing and adding joints requires additional time andlabor, and increases the risk of surging as circulation is stopped andstarted for each joint connection.

In some embodiments, cutting structures may be positioned at variouspoints along the drill string. Cutting structures may be positioned onthe drill string at selected locations, for example, where the diameterof the drill string or BHA changes. FIG. 9A and FIG. 9B depict cuttingstructures 2020 located at or near diameter changes in drill string 2016near to drill bit 2022 and/or BHA 2018. As depicted in FIG. 9C, cuttingstructures 2020 may be positioned at selected locations along the lengthof BHA 2018 and/or drill string 2016 that has a substantially uniformdiameter. Cuttings formed by the cutting structures 2020 may be removedfrom the wellbore by the normal circulation used during the formation ofthe wellbore.

FIG. 10 depicts an embodiment of drill bit 2022 including cuttingstructures 2020. Drill bit 2022 includes downward facing cuttingstructures 2020 b for forming the wellbore. Cutting structures 2020 aare upwardly facing cutting structures for reaming out the wellbore toremove protrusions from the wellbore.

In some embodiments, some cutting structures may be upwardly facing,some cutting structures may be downwardly facing, and/or some cuttingstructures may be oriented substantially perpendicular to the drillstring. FIG. 11 depicts an embodiment of a portion of drilling string2016 including upward facing cutting structures 2020 a, downward facingcutting structures 2020 b, and cutting structures 2020 c that aresubstantially perpendicular to the drill string. Cutting structures 2020a may remove protrusions extending into wellbore 452 that would inhibitupward movement of drill string 2016. Cutting structures 2020 a mayfacilitate reaming of wellbore 452 and/or removal of drill string 2016from the wellbore for drill bit change, BHA maintenance and/or whentotal depth has been reached. Cutting structures 2020 b may removeprotrusions extending into wellbore 452 that would inhibit downwardmovement of drill string 2016. Cutting structures 2020 c may ensure thatenlarged diameter portions of drill string 2016 do not become stuck inwellbore 452.

Positioning downward facing cutting structures 2020 b at variouslocations along a length of the drill string may allow for reaming ofthe wellbore while the drill bit forms additional borehole at the bottomof the wellbore. The ability to ream while drilling may avoid pressuresurges in the wellbore caused by the lifting the drill string. Reamingwhile drilling allows the wellbore to be reamed without interruptingnormal drilling operation. Reaming while drilling allows the wellbore tobe formed in less time because a separate reaming operation is avoided.Upward facing cutting structures 2020 a allow for easy removal of thedrill string from the wellbore.

In some embodiments, the drill string includes a plurality of cuttingstructures positioned along the length of the drill string, but notnecessarily along the entire length of the drill string. The cuttingstructures may be positioned at regular or irregular intervals along thelength of the drill string. Positioning cutting structures along thelength of the drill string allows the entire wellbore to be reamedwithout the need to remove the entire drill string from the wellbore.

Cutting structures may be coupled or attached to the drill string usingtechniques known in the art (for example, by welding). In someembodiments, cutting structures are formed as part of a hinged ring ormulti-piece ring that may be bolted, welded, or otherwise attached tothe drill string. In some embodiments, the distance that the cuttingstructures extend beyond the drill string may be adjustable. Forexample, the cutting element of the cutting structure may includethreading and a locking ring that allows for positioning and setting ofthe cutting element.

In some wellbores, a wash over or over-coring operation may be needed tofree or recover an object in the wellbore that is stuck in the wellboredue to caving, closing, or squeezing of the formation around the object.The object may be a canister, tool, drill string, or other item. Awash-over pipe with downward facing cutting structures at the bottom ofthe pipe may be used. The wash over pipe may also include upward facingcutting structures and downward facing cutting structures at locationsnear the end of the wash-over pipe. The additional upward facing cuttingstructures and downward facing cutting structures may facilitate freeingand/or recovery of the object stuck in the wellbore. The formationholding the object may be cut away rather than broken by relying onhydraulics and force to break the portion of the formation holding thestuck object.

A problem in some formations is that the formed borehole begins to closesoon after the drill string is removed from the borehole. Boreholeswhich close up soon after being formed make it difficult to insertobjects such as tubulars, canisters, tools, or other equipment into thewellbore. In some embodiments, reaming while drilling applied to thecore drill string allows for emplacement of the objects in the center ofthe core drill pipe. The core drill pipe includes one or more upwardfacing cutting structures in addition to cutting structures located atthe end of the core drill pipe. The core drill pipe may be used to formthe wellbore for the object to be inserted in the formation. The objectmay be positioned in the core of the core drill pipe. Then, the coredrill pipe may be removed from the formation. Any parts of the formationthat may inhibit removal of the core drill pipe are cut by the upwardfacing cutting structures as the core drill pipe is removed from theformation.

Replacement canisters may be positioned in the formation using over coredrill pipe. First, the existing canister to be replaced is over cored.The existing canister is then pulled from within the core drill pipewithout removing the core drill pipe from the borehole. The replacementcanister is then run inside of the core drill pipe. Then, the core drillpipe is removed from the borehole. Upward facing cutting structurespositioned along the length of the core drill pipe cut portions of theformation that may inhibit removal of the core drill pipe.

FIG. 12 depicts a schematic drawing of a drilling system. Pilot bit 432may form an opening in the formation. Pilot bit 432 may be followed byfinal diameter bit 434. In some embodiments, pilot bit 432 may be about2.5 cm in diameter. Pilot bit 432 may be one or more meters below finaldiameter bit 434. Pilot bit 432 may rotate in a first direction andfinal diameter bit 434 may rotate in the opposite direction.Counter-rotating bits may allow for the formation of the wellbore alonga desired path. Standard mud may be used in both pilot bit 432 and finaldiameter bit 434. In some embodiments, air or mist may be used as thedrilling fluid in one or both bits.

During some in situ heat treatment processes, wellbores may need to beformed in heated formations. Wellbores drilled into hot formation may beadditional or replacement heater wells, additional or replacementproduction wells and/or monitor wells. In some in situ heat treatmentprocesses, a barrier formed around all or a portion of the in situ heattreatment process is formed by freeze wells that form a low temperaturezone around the freeze wells. A portion of the cooling capacity of thefreeze well equipment may be utilized to cool the equipment needed todrill into the hot formation. Drilling bits may be advanced slowly inhot sections to ensure that the formed wellbore cools sufficiently topreclude drilling problems.

FIG. 13 depicts a schematic drawing of a system for drilling into a hotformation. Cold mud is introduced to drilling bit 434 through conduit436. As the bit penetrates into the formation, the mud cools the bit andthe surrounding formation. In an embodiment, a pilot hole is formedfirst and the wellbore is finished with a larger drill bit later. In anembodiment, the finished wellbore is formed without a pilot hole beingformed. Well advancement is very slow to ensure sufficient cooling.

FIG. 14 depicts a schematic drawing of a system for drilling into a hotformation. Mud is introduced through conduit 436. Closed loop system 438is used to circulate cooling fluid. The cooling fluid cools the drillingmud and the formation as drilling bit 434 slowly penetrates into theformation.

FIG. 15 depicts a schematic drawing of a system for drilling into a hotformation. Mud is introduced through conduit 436. Pilot bit 432 isfollowed by final diameter bit 434. Closed loop system 438 is used tocirculate cooling fluid. The cooling fluid cools the drilling mudsupplied to the drill bits. The cooled drilling mud cools the formation.

In some embodiments, one or more portions of a wellbore may need to beisolated from other portions of the wellbore to establish zonalisolation. In some embodiments, an expandable may be positioned in thewellbore adjacent to a section of the wellbore that is to be isolated. Apig or hydraulic pressure may be used to enlarge the expandable toestablish zonal isolation.

In some embodiments, pathways may be formed in the formation after thewellbores are formed. Pathways may be formed adjacent to heaterwellbores and/or adjacent to production wellbores. The pathways maypromote better fluid flow and/or better heat conduction. In someembodiments, pathways are formed by hydraulically fracturing theformation. Other fracturing techniques may also be used. In someembodiments, small diameter bores may be formed in the formation. Insome embodiments, heating the formation may expand and close orsubstantially close the fractures or bores formed in the formation. Thefractures or holes may extend when the formation is heated. The presenceof fractures of holes may increase heat conduction in the formation.

Some wellbores formed in the formation may be used to facilitateformation of a perimeter barrier around a treatment area. Heat sourcesin the treatment area may heat hydrocarbons in the formation within thetreatment area. The perimeter barrier may be, but is not limited to, alow temperature or frozen barrier formed by freeze wells, dewateringwells, a grout wall formed in the formation, a sulfur cement barrier, abarrier formed by a gel produced in the formation, a barrier formed byprecipitation of salts in the formation, a barrier formed by apolymerization reaction in the formation, and/or sheets driven into theformation. Heat sources, production wells, injection wells, dewateringwells, and/or monitoring wells may be installed in the treatment areadefined by the barrier prior to, simultaneously with, or afterinstallation of the barrier.

A low temperature zone around at least a portion of a treatment area maybe formed by freeze wells. In an embodiment, refrigerant is circulatedthrough freeze wells to form low temperature zones around each freezewell. The freeze wells are placed in the formation so that the lowtemperature zones overlap and form a low temperature zone around thetreatment area. The low temperature zone established by freeze wells ismaintained below the freezing temperature of aqueous fluid in theformation. Aqueous fluid entering the low temperature zone freezes andforms the frozen barrier. In other embodiments, the freeze barrier isformed by batch operated freeze wells. A cold fluid, such as liquidnitrogen, is introduced into the freeze wells to form low temperaturezones around the freeze wells. The fluid is replenished as needed.

In some embodiments, two or more rows of freeze wells are located aboutall or a portion of the perimeter of the treatment area to form a thickinterconnected low temperature zone. Thick low temperature zones may beformed adjacent to areas in the formation where there is a high flowrate of aqueous fluid in the formation. The thick barrier may ensurethat breakthrough of the frozen barrier established by the freeze wellsdoes not occur.

In some embodiments, a double barrier system is used to isolate atreatment area. The double barrier system may be formed with a firstbarrier and a second barrier. The first barrier may be formed around atleast a portion of the treatment area to inhibit fluid from entering orexiting the treatment area. The second barrier may be formed around atleast a portion of the first barrier to isolate an inter-barrier zonebetween the first barrier and the second barrier. The inter-barrier zonemay have a thickness from about 1 m to about 300 m. In some embodiments,the thickness of the inter-barrier zone is from about 10 m to about 100m, or from about 20 m to about 50 m.

The double barrier system may allow greater project depths than a singlebarrier system. Greater depths are possible with the double barriersystem because the stepped differential pressures across the firstbarrier and the second barrier is less than the differential pressureacross a single barrier. The smaller differential pressures across thefirst barrier and the second barrier make a breach of the double barriersystem less likely to occur at depth for the double barrier system ascompared to the single barrier system.

The double barrier system reduces the probability that a barrier breachwill affect the treatment area or the formation on the outside of thedouble barrier. That is, the probability that the location and/or timeof occurrence of the breach in the first barrier will coincide with thelocation and/or time of occurrence of the breach in the second barrieris low, especially if the distance between the first barrier and thesecond barrier is relatively large (for example, greater than about 15m). Having a double barrier may reduce or eliminate influx of fluid intothe treatment area following a breach of the first barrier or the secondbarrier. The treatment area may not be affected if the second barrierbreaches. If the first barrier breaches, only a portion of the fluid inthe inter-barrier zone is able to enter the contained zone. Also, fluidfrom the contained zone will not pass the second barrier. Recovery froma breach of a barrier of the double barrier system may require less timeand fewer resources than recovery from a breach of a single barriersystem. For example, reheating a treatment area zone following a breachof a double barrier system may require less energy than reheating asimilarly sized treatment area zone following a breach of a singlebarrier system.

The first barrier and the second barrier may be the same type of barrieror different types of barriers. In some embodiments, the first barrierand the second barrier are formed by freeze wells. In some embodiments,the first barrier is formed by freeze wells, and the second barrier is agrout wall. The grout wall may be formed of cement, sulfur, sulfurcement, or combinations thereof. In some embodiments, a portion of thefirst barrier and/or a portion of the second barrier is a naturalbarrier, such as an impermeable rock formation.

Vertically positioned freeze wells and/or horizontally positioned freezewells may be positioned around sides of the treatment area. If the upperlayer (the overburden) or the lower layer (the underburden) of theformation is likely to allow fluid flow into the treatment area or outof the treatment area, horizontally positioned freeze wells may be usedto form an upper and/or a lower barrier for the treatment area. In someembodiments, an upper barrier and/or a lower barrier may not benecessary if the upper layer and/or the lower layer are at leastsubstantially impermeable. If the upper freeze barrier is formed,portions of heat sources, production wells, injection wells, and/ordewatering wells that pass through the low temperature zone created bythe freeze wells forming the upper freeze barrier wells may be insulatedand/or heat traced so that the low temperature zone does not adverselyaffect the functioning of the heat sources, production wells, injectionwells and/or dewatering wells passing through the low temperature zone.

Spacing between adjacent freeze wells may be a function of a number ofdifferent factors. The factors may include, but are not limited to,physical properties of formation material, type of refrigeration system,coldness and thermal properties of the refrigerant, flow rate ofmaterial into or out of the treatment area, time for forming the lowtemperature zone, and economic considerations. Consolidated or partiallyconsolidated formation material may allow for a large separationdistance between freeze wells. A separation distance between freezewells in consolidated or partially consolidated formation material maybe from about 3 m to about 20 m, about 4 m to about 15 m, or about 5 mto about 10 m. In an embodiment, the spacing between adjacent freezewells is about 5 m. Spacing between freeze wells in unconsolidated orsubstantially unconsolidated formation material, such as in tar sand,may need to be smaller than spacing in consolidated formation material.A separation distance between freeze wells in unconsolidated materialmay be from about 1 m to about 5 m.

Freeze wells may be placed in the formation so that there is minimaldeviation in orientation of one freeze well relative to an adjacentfreeze well. Excessive deviation may create a large separation distancebetween adjacent freeze wells that may not permit formation of aninterconnected low temperature zone between the adjacent freeze wells.Factors that influence the manner in which freeze wells are insertedinto the ground include, but are not limited to, freeze well insertiontime, depth that the freeze wells are to be inserted, formationproperties, desired well orientation, and economics.

Relatively low depth wellbores for freeze wells may be impacted and/orvibrationally inserted into some formations. Wellbores for freeze wellsmay be impacted and/or vibrationally inserted into formations to depthsfrom about 1 m to about 100 m without excessive deviation in orientationof freeze wells relative to adjacent freeze wells in some types offormations.

Wellbores for freeze wells placed deep in the formation, or wellboresfor freeze wells placed in formations with layers that are difficult toimpact or vibrate a well through, may be placed in the formation bydirectional drilling and/or geosteering. Acoustic signals, electricalsignals, magnetic signals, and/or other signals produced in a firstwellbore may be used to guide directionally drilling of adjacentwellbores so that desired spacing between adjacent wells is maintained.Tight control of the spacing between wellbores for freeze wells is animportant factor in minimizing the time for completion of barrierformation.

In some embodiments, one or more portions of freeze wells may be angledin the formation. The freeze wells may be angled in the formationadjacent to aquifers. In some embodiments, the angled portions areangled outwards from the treatment area. In some embodiments, the angledportions may be angled inwards towards the treatment area. The angledportions of the freeze wells allow extra length of freeze well to bepositioned in the aquifer zones. Also, the angled portions of the freezewells may reduce the shear load applied to the frozen barrier by waterflowing in the aquifer.

After formation of the wellbore for the freeze well, the wellbore may bebackflushed with water adjacent to the part of the formation that is tobe reduced in temperature to form a portion of the freeze barrier. Thewater may displace drilling fluid remaining in the wellbore. The watermay displace indigenous gas in cavities adjacent to the formation. Insome embodiments, the wellbore is filled with water from a conduit up tothe level of the overburden. In some embodiments, the wellbore isbackflushed with water in sections. The wellbore maybe treated insections having lengths of about 6 m, 10 m, 14 m, 17 m, or greater.Pressure of the water in the wellbore is maintained below the fracturepressure of the formation. In some embodiments, the water, or a portionof the water is removed from the wellbore, and a freeze well is placedin the formation.

FIG. 16 depicts an embodiment of freeze well 440. Freeze well 440 mayinclude canister 442, inlet conduit 444, spacers 446, and wellcap 448.Spacers 446 may position inlet conduit 444 in canister 442 so that anannular space is formed between the canister and the conduit. Spacers446 may promote turbulent flow of refrigerant in the annular spacebetween inlet conduit 444 and canister 442, but the spacers may alsocause a significant fluid pressure drop. Turbulent fluid flow in theannular space may be promoted by roughening the inner surface ofcanister 442, by roughening the outer surface of inlet conduit 444,and/or by having a small cross-sectional area annular space that allowsfor high refrigerant velocity in the annular space. In some embodiments,spacers are not used. Wellhead 450 may suspend canister 442 in wellbore452.

Formation refrigerant may flow through cold side conduit 454 from arefrigeration unit to inlet conduit 444 of freeze well 440. Theformation refrigerant may flow through an annular space between inletconduit 444 and canister 442 to warm side conduit 456. Heat may transferfrom the formation to canister 442 and from the canister to theformation refrigerant in the annular space. Inlet conduit 444 may beinsulated to inhibit heat transfer to the formation refrigerant duringpassage of the formation refrigerant into freeze well 440. In anembodiment, inlet conduit 444 is a high density polyethylene tube. Atcold temperatures, some polymers may exhibit a large amount of thermalcontraction. For example, a 260 m initial length of polyethylene conduitsubjected to a temperature of about −25° C. may contract by 6 m or more.If a high density polyethylene conduit, or other polymer conduit, isused, the large thermal contraction of the material must be taken intoaccount in determining the final depth of the freeze well. For example,the freeze well may be drilled deeper than needed, and the conduit maybe allowed to shrink back during use. In some embodiments, inlet conduit444 is an insulated metal tube. In some embodiments, the insulation maybe a polymer coating, such as, but not limited to, polyvinylchloride,high density polyethylene, and/or polystyrene.

Freeze well 440 may be introduced into the formation using a coiledtubing rig. In an embodiment, canister 442 and inlet conduit 444 arewound on a single reel. The coiled tubing rig introduces the canisterand inlet conduit 444 into the formation. In an embodiment, canister 442is wound on a first reel and inlet conduit 444 is wound on a secondreel. The coiled tubing rig introduces canister 442 into the formation.Then, the coiled tubing rig is used to introduce inlet conduit 444 intothe canister. In other embodiments, freeze well is assembled in sectionsat the wellbore site and introduced into the formation.

An insulated section of freeze well 440 may be placed adjacent tooverburden 458. An uninsulated section of freeze well 440 may be placedadjacent to layer or layers 460 where a low temperature zone is to beformed. In some embodiments, uninsulated sections of the freeze wellsmay be positioned adjacent only to aquifers or other permeable portionsof the formation that would allow fluid to flow into or out of thetreatment area. Portions of the formation where uninsulated sections ofthe freeze wells are to be placed may be determined using analysis ofcores and/or logging techniques.

Various types of refrigeration systems may be used to form a lowtemperature zone. Determination of an appropriate refrigeration systemmay be based on many factors, including, but not limited to: a type offreeze well; a distance between adjacent freeze wells; a refrigerant; atime frame in which to form a low temperature zone; a depth of the lowtemperature zone; a temperature differential to which the refrigerantwill be subjected; one or more chemical and/or physical properties ofthe refrigerant; one or more environmental concerns related to potentialrefrigerant releases, leaks or spills; one or more economic factors;water flow rate in the formation; composition and/or properties offormation water including the salinity of the formation water; and oneor more properties of the formation such as thermal conductivity,thermal diffusivity, and heat capacity.

A circulated fluid refrigeration system may utilize a liquid refrigerant(formation refrigerant) that is circulated through freeze wells. Some ofthe desired properties for the formation refrigerant are: low workingtemperature, low viscosity at and near the working temperature, highdensity, high specific heat capacity, high thermal conductivity, lowcost, low corrosiveness, and low toxicity. A low working temperature ofthe formation refrigerant allows a large low temperature zone to beestablished around a freeze well. The low working temperature offormation refrigerant should be about −20° C. or lower. Formationrefrigerants having low working temperatures of at least −60° C. mayinclude aqua ammonia, potassium formate solutions such as Dynalene®HC-50 (Dynalene® Heat Transfer Fluids (Whitehall, Pa., U.S.A.)) orFREEZIUM® (Kemira Chemicals (Helsinki, Finland)); silicone heat transferfluids such as Syltherm XLT® (Dow Corning Corporation (Midland, Mich.,U.S.A.); hydrocarbon refrigerants such as propylene; andchlorofluorocarbons such as R-22. Aqua ammonia is a solution of ammoniaand water with a weight percent of ammonia between about 20% and about40%. Aqua ammonia has several properties and characteristics that makeuse of aqua ammonia as the formation refrigerant desirable. Suchproperties and characteristics include, but are not limited to, a verylow freezing point, a low viscosity, ready availability, and low cost.

Formation refrigerant that is capable of being chilled below a freezingtemperature of aqueous formation fluid may be used to form the lowtemperature zone around the treatment area. The following equation (theSanger equation) may be used to model the time t1 needed to form afrozen barrier of radius R around a freeze well having a surfacetemperature of T_(s):

$\begin{matrix}{{t_{1} = {\frac{R^{2}L_{1}}{4k_{f}v_{s}}\left( {{2\ln \frac{R}{r_{o}}} - 1 + \frac{c_{vf}v_{s}}{L_{1}}} \right)}}{{in}\mspace{14mu} {which}\text{:}}{L_{1} = {L\frac{a_{r}^{2} - 1}{2\ln \; a_{r}}c_{vu}v_{o}}}{a_{r} = {\frac{R_{A}}{R}.}}} & \left( {{EQN}.\mspace{14mu} 2} \right)\end{matrix}$

In these equations, k_(f) is the thermal conductivity of the frozenmaterial; c_(vf) and c_(vu) are the volumetric heat capacity of thefrozen and unfrozen material, respectively; r_(o) is the radius of thefreeze well; v_(s) is the temperature difference between the freeze wellsurface temperature T_(s) and the freezing point of water T_(o); v_(o)is the temperature difference between the ambient ground temperatureT_(g) and the freezing point of water T_(o); L is the volumetric latentheat of freezing of the formation; R is the radius at thefrozen-unfrozen interface; and R_(A) is a radius at which there is noinfluence from the refrigeration pipe. The Sanger equation may provide aconservative estimate of the time needed to form a frozen barrier ofradius R because the equation does not take into considerationsuperposition of cooling from other freeze wells. The temperature of theformation refrigerant is an adjustable variable that may significantlyaffect the spacing between freeze wells.

EQN. 2 implies that a large low temperature zone may be formed by usinga refrigerant having an initial temperature that is very low. The use offormation refrigerant having an initial cold temperature of about −30°C. or lower is desirable. Formation refrigerants having initialtemperatures warmer than about −30° C. may also be used, but suchformation refrigerants require longer times for the low temperaturezones produced by individual freeze wells to connect. In addition, suchformation refrigerants may require the use of closer freeze wellspacings and/or more freeze wells.

The physical properties of the material used to construct the freezewells may be a factor in the determination of the coldest temperature ofthe formation refrigerant used to form the low temperature zone aroundthe treatment area. Carbon steel may be used as a construction materialof freeze wells. ASTM A333 grade 6 steel alloys and ASTM A333 grade 3steel alloys may be used for low temperature applications. ASTM A333grade 6 steel alloys typically contain little or no nickel and have alow working temperature limit of about −50° C. ASTM A333 grade 3 steelalloys typically contain nickel and have a much colder low workingtemperature limit. The nickel in the ASTM A333 grade 3 alloy addsductility at cold temperatures, but also significantly raises the costof the metal. In some embodiments, the coldest temperature of therefrigerant is from about −35° C. to about −55° C., from about −38° C.to about −47° C., or from about −40° C. to about −45° C. to allow forthe use of ASTM A333 grade 6 steel alloys for construction of canistersfor freeze wells. Stainless steels, such as 304 stainless steel, may beused to form freeze wells, but the cost of stainless steel is typicallymuch more than the cost of ASTM A333 grade 6 steel alloy.

In some embodiments, the metal used to form the canisters of the freezewells may be provided as pipe. In some embodiments, the metal used toform the canisters of the freeze wells may be provided in sheet form.The sheet metal may be longitudinally welded to form pipe and/or coiledtubing. Forming the canisters from sheet metal may improve the economicsof the system by allowing for coiled tubing insulation and by reducingthe equipment and manpower needed to form and install the canistersusing pipe.

A refrigeration unit may be used to reduce the temperature of formationrefrigerant to the low working temperature. In some embodiments, therefrigeration unit may utilize an ammonia vaporization cycle.Refrigeration units are available from Cool Man Inc. (Milwaukee, Wis.,U.S.A.), Gartner Refrigeration & Manufacturing (Minneapolis, Minn.,U.S.A.), and other suppliers. In some embodiments, a cascadingrefrigeration system may be utilized with a first stage of ammonia and asecond stage of carbon dioxide. The circulating refrigerant through thefreeze wells may be 30% by weight ammonia in water (aqua ammonia).Alternatively, a single stage carbon dioxide refrigeration system may beused.

In some embodiments, refrigeration systems for forming a low temperaturebarrier for a treatment area may be installed and activated beforefreeze wells are formed in the formation. As the freeze well wellboresare formed, freeze wells may be installed in the wellbores. Refrigerantmay be circulated through the wellbores soon after the freeze well isinstalled into the wellbore. Limiting the time between wellboreformation and cooling initiation may limit or inhibit cross mixing offormation water between different aquifers.

Grout may be used in combination with freeze wells to provide a barrierfor the in situ heat treatment process. The grout fills cavities (vugs)in the formation and reduces the permeability of the formation. Groutmay have higher thermal conductivity than gas and/or formation fluidthat fills cavities in the formation. Placing grout in the cavities mayallow for faster low temperature zone formation. The grout forms aperpetual barrier in the formation that may strengthen the formation.The use of grout in unconsolidated or substantially unconsolidatedformation material may allow for larger well spacing than is possiblewithout the use of grout. The combination of grout and the lowtemperature zone formed by freeze wells may constitute a double barrierfor environmental regulation purposes. In some embodiments, the grout isintroduced into the formation as a liquid, and the liquid sets in theformation to form a solid. The grout may be any type of grout, includingbut not limited to, fine cement, micro fine cement, sulfur, sulfurcement, viscous thermoplastics, and/or waxes. The grout may includesurfactants, stabilizers or other chemicals that modify the propertiesof the grout. For example, the presence of surfactant in the grout maypromote entry of the grout into small openings in the formation.

Grout may be introduced into the formation through freeze wellwellbores. The grout may be allowed to set. The integrity of the groutwall may be checked. The integrity of the grout wall may be checked bylogging techniques and/or by hydrostatic testing. If the permeability ofa grouted section is too high, additional grout may be introduced intothe formation through freeze well wellbores. After the permeability ofthe grouted section is sufficiently reduced, freeze wells may beinstalled in the freeze well wellbores.

Grout may be injected into the formation at a pressure that is high, butbelow the fracture pressure of the formation. In some embodiments,grouting is performed in 16 m increments in the freeze wellbore. Largeror smaller increments may be used if desired. In some embodiments, groutis only applied to certain portions of the formation. For example, groutmay be applied to the formation through the freeze wellbore onlyadjacent to aquifer zones and/or to relatively high permeability zones(for example, zones with a permeability greater than about 0.1 darcy).Applying grout to aquifers may inhibit migration of water from oneaquifer to a different aquifer. For grout placed in the formationthrough freeze well wellbores, the grout may inhibit water migrationbetween aquifers during formation of the low temperature zone. The groutmay also inhibit water migration between aquifers when an establishedlow temperature zone is allowed to thaw.

In some embodiments, the grout used to form a barrier may be fine cementand micro fine cement. Cement may provide structural support in theformation. Fine cement may be ASTM type 3 Portland cement. Fine cementmay be less expensive than micro fine cement. In an embodiment, a freezewellbore is formed in the formation. Selected portions of the freezewellbore are grouted using fine cement. Then, micro fine cement isinjected into the formation through the freeze wellbore. The fine cementmay reduce the permeability down to about 10 millidarcy. The micro finecement may further reduce the permeability to about 0.1 millidarcy.After the grout is introduced into the formation, a freeze wellborecanister may be inserted into the formation. The process may be repeatedfor each freeze well that will be used to form the barrier.

In some embodiments, fine cement is introduced into every other freezewellbore. Micro fine cement is introduced into the remaining wellbores.For example, grout may be used in a formation with freeze wellbores setat about 5 m spacing. A first wellbore is drilled and fine cement isintroduced into the formation through the wellbore. A freeze wellcanister is positioned in the first wellbore. A second wellbore isdrilled 10 m away from the first wellbore. Fine cement is introducedinto the formation through the second wellbore. A freeze well canisteris positioned in the second wellbore. A third wellbore is drilledbetween the first wellbore and the second wellbore. In some embodiments,grout from the first and/or second wellbores may be detected in thecuttings of the third wellbore. Micro fine cement is introduced into theformation through the third wellbore. A freeze wellbore canister ispositioned in the third wellbore. The same procedure is used to form theremaining freeze wells that will form the barrier around the treatmentarea.

In some embodiments, wax may be used to form a grout barrier. Waxbarriers may be formed in wet, dry or oil wetted formations. Liquid waxintroduced into the formation may permeate into adjacent rock andfractures in the formation. Liquid wax may permeate into rock to fillmicroscopic as well as macroscopic pores and vugs in the rock. The waxsolidifies to form a grout barrier that inhibits fluid flow into or outof a treatment area. A wax grout barrier may provide a minimal amount ofstructural support in the formation. Molten wax may reduce the strengthof poorly consolidated soil by reducing inter-grain friction so that thepoorly consolidated soil sloughs or liquefies. Poorly consolidatedlayers may be consolidated by use of cement or other binding agentsbefore introduction of molten wax.

The wax of a barrier may be a branched paraffin to, for example, inhibitbiological degradation of the wax. The wax may include stabilizers,surfactants or other chemicals that modify the physical and/or chemicalproperties of the wax. The physical properties may be tailored to meetspecific needs. The wax may melt at a relative low temperature (forexample, the wax may have a typical melting point of about 52° C.). Thetemperature at which the wax congeals may be at least 5° C., 10° C., 20°C., or 30° C. above the ambient temperature of the formation prior toany heating of the formation. When molten, the wax may have a relativelylow viscosity (for example, 4 to 10 cp at about 99° C.). The flash pointof the wax may be relatively high (for example, the flash point may beover 204° C.). The wax may have a density less than the density of waterand may have a heat capacity that is less than half the heat capacity ofwater. The solid wax may have a low thermal conductivity (for example,about 0.18 W/m ° C.) so that the solid wax is a thermal insulator. Waxessuitable for forming a barrier are available as WAXFIX™ from CarterTechnologies Company (Sugar Land, Tex., U.S.A.).

In some embodiments, a wax barrier or wax barriers may be used as thebarriers for the in situ heat treatment process. In some embodiments, awax barrier may be used in conjunction with freeze wells that form a lowtemperature barrier around the treatment area. In some embodiments, thewax barrier is formed and freeze wells are installed in the wellboresused for introducing wax into the formation. In some embodiments, thewax barrier is formed in wellbores offset from the freeze wellwellbores. The wax barrier may be on the outside or the inside of thefreeze wells. In some embodiments, a wax barrier may be formed on boththe inside and outside of the freeze wells. The wax barrier may inhibitwater flow in the formation that would inhibit the formation of the lowtemperature zone by the freeze wells. In some embodiments, a wax barrieris formed in the inter-barrier zone between two freeze barriers of adouble barrier system.

Wellbores may be formed in the formation around the treatment area at aclose spacing. In some embodiments, the spacing is from about 1.5 m toabout 4 m. Low temperature heaters may be inserted in the wellbores. Theheaters may operate at temperatures from about 260° C. to about 320° C.so that the temperature at the formation face is below the pyrolysistemperature of hydrocarbons in the formation. The heaters may beactivated to heat the formation until the overlap between two adjacentheaters raises the temperature of the zone between the two heaters abovethe melting temperature of the wax. Heating the formation to obtainsuperposition of heat with a temperature above the melting temperatureof the wax may take one month, two months, or longer. After heating, theheaters may be turned off. Wax may be introduced into the wellbores toform the barrier. The wax may flow into the formation and fill anyfractures and porosity that has been heated. The wax congeals when thewax flows to cold regions beyond the heated circumference. This waxbarrier formation method may form a more complete barrier than someother methods of wax barrier formation, but the time for heating may belonger than for some of the other methods. Also, if a low temperaturebarrier is to be formed with the freeze wells placed in the wellboresused for wax injection, the freeze wells will have to remove the heatsupplied to the formation to allow for introduction of the wax. The lowtemperature barrier may take longer to form.

In some embodiments, the wax barrier may be formed using a conduitplaced in the wellbore. FIG. 17A depicts an embodiment of a system forforming a wax barrier in a formation. Wellbore 452 may extend into oneor more layers 460 below overburden 458. Wellbore 452 may be an openwellbore below underburden 458. One or more of the layers 460 mayinclude fracture systems 462. One or more of the layers may be vuggy sothat the layer or a portion of the layer has a high porosity. Conduit464 may be positioned in wellbore 452. In some embodiments, lowtemperature heater 466 may be strapped or attached to conduit 464. Insome embodiments, conduit 464 may be a heater element. Heater 466 may beoperated so that the heater does not cause pyrolysis of hydrocarbonsadjacent to the heater. At least a portion of wellbore 452 may be filledwith fluid. The fluid may be formation fluid or water. Heater 466 may beactivated to heat the fluid. A portion of the heated fluid may moveoutwards from heater 466 into the formation. The heated fluid may beinjected into the fractures and permeable vuggy zones. The heated fluidmay be injected into the fractures and permeable vuggy zones byintroducing heated wax into wellbore 452 in the annular space betweenconduit 464 and the wellbore. The introduced wax flows to the areasheated by the fluid and congeals when the fluid reaches cold regions notheated by the fluid. The wax fills fracture systems 462 and permeablevuggy pathways heated by the fluid, but the wax may not permeate througha significant portion of the rock matrix as when the hot wax isintroduced into a heated formation as described above. The wax flowsinto fracture systems 462 a sufficient distance to join with waxinjected from an adjacent well so that a barrier to fluid flow throughthe fracture systems forms when the wax congeals. A portion of wax maycongeal along the wall of a fracture or a vug without completelyblocking the fracture or filling the vug. The congealed wax may act asan insulator and allow additional liquid wax to flow beyond thecongealed portion to penetrate deeply into the formation and formblockages to fluid flow when the wax cools below the melting temperatureof the wax.

Wax in the annular space of wellbore 452 between conduit 464 and theformation may be removed through conduit by displacing the wax withwater or other fluid. Conduit 464 may be removed and a freeze well maybe installed in the wellbore. This method may use less wax than themethod described above. The heating of the fluid may be accomplished inless than a week or within a day. The small amount of heat input mayallow for quicker formation of a low temperature barrier if freeze wellsare to be positioned in the wellbores used to introduce wax into theformation.

In some embodiments, a heater may be suspended in the well without aconduit that allows for removal of excess wax from the wellbore. The waxmay be introduced into the well. After wax introduction, the heater maybe removed from the well. In some embodiments, a conduit may bepositioned in the wellbore, but a heater may not be coupled to theconduit. Hot wax may be circulated through the conduit so that the waxenters fractures systems and/or vugs adjacent to the wellbore.

In some embodiments, wax may be used during the formation of a wellboreto improve inter-zonal isolation and protect a low-pressure zone frominflow from a high-pressure zone. During wellbore formation where a highpressure zone and a low pressure zone are penetrated by a commonwellbore, it is possible for the high pressure zone to flow into the lowpressure zone and cause an underground blowout. To avoid this, thewellbore may be formed through the first zone. Then, an intermediatecasing may be set and cemented through the first zone. Setting casingmay be time consuming and expensive. Instead of setting a casing, waxmay be used to seal the first zone. The wax may also inhibit or preventmixing of high salinity brines from lower, high pressure zones withfresher brines in upper, lower pressure zones.

FIG. 17B depicts wellbore 452 drilled to a first depth in formation 758.After the surface casing for wellbore 452 is set and cemented in place,the wellbore is drilled to the first depth which passes through apermeable zone, such as an aquifer. The permeable zone may be fracturesystem 462′. In some embodiments, a heater is placed in wellbore 452 toheat the vertical interval of fracture system 462′. In some embodiments,hot fluid is circulated in wellbore 452 to heat the vertical interval offracture system 462′. After heating, molten wax is pumped down wellbore452. The molten wax flows a selected distance into fracture system 462′before the wax cools sufficiently to solidify and form a seal. Themolten wax is introduced into formation 758 at a pressure below thefracture pressure of the formation. In some embodiments, pressure ismaintained on the wellhead until the wax has solidified. In someembodiments, the wax is allowed to cool until the wax in wellbore 452 isalmost to the congealing temperature of the wax. The wax in wellbore 452may then be displaced out of the wellbore. The wax makes the portion offormation 758 near wellbore 452 into a substantially impermeable zone.Wellbore 452 may be drilled to depth through one or more permeable zonesthat are at higher pressures than the pressure in the first permeablezone, such as fracture system 462″. Congealed wax in fracture system462′ may inhibit blowout into the lower pressure zone. FIG. 17C depictswellbore 452 drilled to depth with congealed wax 492 in formation 758.

In some embodiments, wax may be used to contain and inhibit migration ina subsurface formation that has liquid hydrocarbon contaminants (forexample, compounds such as benzene, toluene, ethylbenzene and xylene)condensed in fractures in the formation. The location of thecontaminants may be surrounded with heated wax injection wells. Wax maybe introduced into the wells to form an outer wax barrier. The waxinjected into the fractures from the wax injection wells may mix withthe contaminants. The contaminants may be solubilized into the wax. Whenthe wax congeals, the contaminants may be permanently contained in thesolid wax phase.

In some embodiments, a composition that includes a cross-linkablepolymer may be used with or in addition to a wax. Such composition maybe provided to the formation as is described above for the wax. Thecomposition may be configured to react and solidify after a selectedtime in the formation, thereby allowing the composition to be providedas a liquid to the formation. The cross-linkable polymer may include,for example, acrylates, methacrylates, urethanes, and/or epoxies. Across-linking initiator may be included in the composition. Thecomposition may also include a cross-linking inhibitor. Thecross-linking inhibitor may be configured to degrade while in theformation, thereby allowing the composition to solidify.

In situ heat treatment processes and solution mining processes may heatthe treatment area, remove mass from the treatment area, and greatlyincrease the permeability of the treatment area. In certain embodiments,the treatment area after being treated may have a permeability of atleast 0.1 darcy. In some embodiments, the treatment area after beingtreated has a permeability of at least 1 darcy, of at least 10 darcy, orof at least 100 darcy. The increased permeability allows the fluid tospread in the formation into fractures, microfractures, and/or porespaces in the formation. Outside of the treatment area, the permeabilitymay remain at the initial permeability of the formation. The increasedpermeability allows fluid introduced to flow easily within theformation.

In certain embodiments, a barrier may be formed in the formation after asolution mining process and/or an in situ heat treatment process byintroducing a fluid into the formation. The barrier may inhibitformation fluid from entering the treatment area after the solutionmining and/or in situ heat treatment processes have ended. The barrierformed by introducing fluid into the formation may allow for isolationof the treatment area.

The fluid introduced into the formation to form a barrier may includewax, bitumen, heavy oil, sulfur, polymer, gel, saturated salinesolution, and/or one or more reactants that react to form a precipitate,solid or high viscosity fluid in the formation. In some embodiments,bitumen, heavy oil, reactants and/or sulfur used to form the barrier areobtained from treatment facilities associated with the in situ heattreatment process. For example, sulfur may be obtained from a Clausprocess used to treat produced gases to remove hydrogen sulfide andother sulfur compounds.

The fluid may be introduced into the formation as a liquid, vapor, ormixed phase fluid. The fluid may be introduced into a portion of theformation that is at an elevated temperature. In some embodiments, thefluid is introduced into the formation through wells located near aperimeter of the treatment area. The fluid may be directed away from thetreatment area. The elevated temperature of the formation maintains orallows the fluid to have a low viscosity so that the fluid moves awayfrom the wells. A portion of the fluid may spread outwards in theformation towards a cooler portion of the formation. The relatively highpermeability of the formation allows fluid introduced from one wellboreto spread and mix with fluid introduced from other wellbores. In thecooler portion of the formation, the viscosity of the fluid increases, aportion of the fluid precipitates, and/or the fluid solidifies orthickens so that the fluid forms the barrier to flow of formation fluidinto or out of the treatment area.

In some embodiments, a low temperature barrier formed by freeze wellssurrounds all or a portion of the treatment area. As the fluidintroduced into the formation approaches the low temperature barrier,the temperature of the formation becomes colder. The colder temperatureincreases the viscosity of the fluid, enhances precipitation, and/orsolidifies the fluid to form the barrier to the flow of formation fluidinto or out of the formation. The fluid may remain in the formation as ahighly viscous fluid or a solid after the low temperature barrier hasdissipated.

In certain embodiments, saturated saline solution is introduced into theformation. Components in the saturated saline solution may precipitateout of solution when the solution reaches a colder temperature. Thesolidified particles may form the barrier to the flow of formation fluidinto or out of the formation. The solidified components may besubstantially insoluble in formation fluid.

In certain embodiments, brine is introduced into the formation as areactant. A second reactant, such as carbon dioxide, may be introducedinto the formation to react with the brine. The reaction may generate amineral complex that grows in the formation. The mineral complex may besubstantially insoluble to formation fluid. In an embodiment, the brinesolution includes a sodium and aluminum solution. The second reactantintroduced in the formation is carbon dioxide. The carbon dioxide reactswith the brine solution to produce dawsonite. The minerals may solidifyand form the barrier to the flow of formation fluid into or out of theformation.

In some embodiments, the barrier may be formed around a treatment areausing sulfur. Advantageously, elemental sulfur is insoluble in water.Liquid and/or solid sulfur in the formation may form a barrier toformation fluid flow into or out of the treatment area.

A sulfur barrier may be established in the formation during or beforeinitiation of heating to heat the treatment area of the in situ heattreatment process. In some embodiments, sulfur may be introduced intowellbores in the formation that are located between the treatment areaand a first barrier (for example, a low temperature barrier establishedby freeze wells). The formation adjacent to the wellbores that thesulfur is introduced into may be dewatered. In some embodiments, theformation adjacent to the wellbores that the sulfur is introduced intois heated to facilitate removal of water and to prepare the wellboresand adjacent formation for the introduction of sulfur. The formationadjacent to the wellbores may be heated to a temperature below thepyrolysis temperature of hydrocarbons in the formation. The formationmay be heated so that the temperature of a portion of the formationbetween two adjacent heaters is influenced by both heaters. In someembodiments, the heat may increase the permeability of the formation sothat a first wellbore is in fluid communication with an adjacentwellbore.

After the formation adjacent to the wellbores is heated, molten sulfurat a temperature below the pyrolysis temperature of hydrocarbons in theformation is introduced into the formation. Over a certain temperaturerange, the viscosity of molten sulfur increases with increasingtemperature. The molten sulfur introduced into the formation may be nearthe melting temperature of sulfur (about 115° C.) so that the sulfur hasa relatively low viscosity (about 4-10 cp). Heaters in the wellbores maybe temperature limited heaters with Curie temperatures near the meltingtemperature of sulfur so that the temperature of the molten sulfur staysrelatively constant and below temperatures resulting in the formation ofviscous molten sulfur. In some embodiments, the region adjacent to thewellbores may be heated to a temperature above the melting point ofsulfur, but below the pyrolysis temperature of hydrocarbons in theformation. The heaters may be turned off and the temperature in thewellbores may be monitored (for example, using a fiber optic temperaturemonitoring system). When the temperature in the wellbore cools to atemperature near the melting temperature of sulfur, molten sulfur may beintroduced into the formation.

The sulfur introduced into the formation is allowed to flow and diffuseinto the formation from the wellbores. As the sulfur enters portions ofthe formation below the melting temperature, the sulfur solidifies andforms a barrier to fluid flow in the formation. Sulfur may be introduceduntil the formation is not able to accept additional sulfur. Heating maybe stopped, and the formation may be allowed to naturally cool so thatthe sulfur in the formation solidifies. After introduction of thesulfur, the integrity of the formed barrier may be tested using pulsetests and/or tracer tests.

A barrier may be formed around the treatment area after the in situ heattreatment process. The sulfur may form a substantially permanent barrierin the formation. In some embodiments, a low temperature barrier formedby freeze wells surrounds the treatment area. Sulfur may be introducedon one or both sides of the low temperature barrier to form a barrier inthe formation. The sulfur may be introduced into the formation as vaporor a liquid. As the sulfur approaches the low temperature barrier, thesulfur may condense and/or solidify in the formation to form thebarrier.

In some embodiments, the sulfur may be introduced in the heated portionof the portion. The sulfur may be introduced into the formation throughwells located near the perimeter of the treatment area. The temperatureof the formation may be hotter than the vaporization temperature ofsulfur (about 445° C.). The sulfur may be introduced as a liquid, vaporor mixed phase fluid. If a part of the introduced sulfur is in theliquid phase, the heat of the formation may vaporize the sulfur. Thesulfur may flow outwards from the introduction wells towards coolerportions of the formation. The sulfur may condense and/or solidify inthe formation to form the barrier.

In some embodiments, the Claus reaction may be used to form sulfur inthe formation after the in situ heat treatment process. The Clausreaction is a gas phase equilibrium reaction.

The Claus reaction is:

4H₂S+2SO₂

3S₂+4H₂O  (EQN. 3)

Hydrogen sulfide may be obtained by separating the hydrogen sulfide fromthe produced fluid of an ongoing in situ heat treatment process. Aportion of the hydrogen sulfide may be burned to form the needed sulfurdioxide. Hydrogen sulfide may be introduced into the formation through anumber of wells in the formation. Sulfur dioxide may be introduced intothe formation through other wells. The wells used for injecting sulfurdioxide or hydrogen sulfide may have been production wells, heaterwells, monitor wells or other type of well during the in situ heattreatment process. The wells used for injecting sulfur dioxide orhydrogen sulfide may be near the perimeter of the treatment area. Thenumber of wells may be enough so that the formation in the vicinity ofthe injection wells does not cool to a point where the sulfur dioxideand the hydrogen sulfide can form sulfur and condense, rather thanremain in the vapor phase. The wells used to introduce the sulfurdioxide into the formation may also be near the perimeter of thetreatment area. In some embodiments, the hydrogen sulfide and sulfurdioxide may be introduced into the formation through the same wells (forexample, through two conduits positioned in the same wellbore). Thehydrogen sulfide and the sulfur dioxide may react in the formation toform sulfur and water. The sulfur may flow outwards in the formation andcondense and/or solidify to form the barrier in the formation.

The sulfur barrier may form in the formation beyond the area wherehydrocarbons in formation fluid generated by the heat treatment processcondense in the formation. Regions near the perimeter of the treatedarea may be at lower temperatures than the treated area. Sulfur maycondense and/or solidify from the vapor phase in these lower temperatureregions. Additional hydrogen sulfide, and/or sulfur dioxide may diffuseto these lower temperature regions. Additional sulfur may form by theClaus reaction to maintain an equilibrium concentration of sulfur in thevapor phase. Eventually, a sulfur barrier may form around the treatedzone. The vapor phase in the treated region may remain as an equilibriummixture of sulfur, hydrogen sulfide, sulfur dioxide, water vapor andother vapor products present or evolving from the formation.

The conversion to sulfur is favored at lower temperatures, so theconversion of hydrogen sulfide and sulfur dioxide to sulfur may takeplace a distance away from the wells that introduce the reactants intothe formation. The Claus reaction may result in the formation of sulfurwhere the temperature of the formation is cooler (for example where thetemperature of the formation is at temperatures from about 180° C. toabout 240° C.).

A temperature monitoring system may be installed in wellbores of freezewells and/or in monitor wells adjacent to the freeze wells to monitorthe temperature profile of the freeze wells and/or the low temperaturezone established by the freeze wells. The monitoring system may be usedto monitor progress of low temperature zone formation. The monitoringsystem may be used to determine the location of high temperature areas,potential breakthrough locations, or breakthrough locations after thelow temperature zone has formed. Periodic monitoring of the temperatureprofile of the freeze wells and/or low temperature zone established bythe freeze wells may allow additional cooling to be provided topotential trouble areas before breakthrough occurs. Additional coolingmay be provided at or adjacent to breakthroughs and high temperatureareas to ensure the integrity of the low temperature zone around thetreatment area. Additional cooling may be provided by increasingrefrigerant flow through selected freeze wells, installing an additionalfreeze well or freeze wells, and/or by providing a cryogenic fluid, suchas liquid nitrogen, to the high temperature areas. Providing additionalcooling to potential problem areas before breakthrough occurs may bemore time efficient and cost efficient than sealing a breach, reheatinga portion of the treatment area that has been cooled by influx of fluid,and/or remediating an area outside of the breached frozen barrier.

In some embodiments, a traveling thermocouple may be used to monitor thetemperature profile of selected freeze wells or monitor wells. In someembodiments, the temperature monitoring system includes thermocouplesplaced at discrete locations in the wellbores of the freeze wells, inthe freeze wells, and/or in the monitoring wells. In some embodiments,the temperature monitoring system comprises a fiber optic temperaturemonitoring system.

Fiber optic temperature monitoring systems are available from Sensornet(London, United Kingdom), Sensa (Houston, Tex., U.S.A.), Luna Energy(Blacksburg, Va., U.S.A.), Lios Technology GMBH (Cologne, Germany),Oxford Electronics Ltd. (Hampshire, United Kingdom), and Sabeus SensorSystems (Calabasas, Calif., U.S.A.). The fiber optic temperaturemonitoring system includes a data system and one or more fiber opticcables. The data system includes one or more lasers for sending light tothe fiber optic cable; and one or more computers, software andperipherals for receiving, analyzing, and outputting data. The datasystem may be coupled to one or more fiber optic cables.

A single fiber optic cable may be several kilometers long. The fiberoptic cable may be installed in many freeze wells and/or monitor wells.In some embodiments, two fiber optic cables may be installed in eachfreeze well and/or monitor well. The two fiber optic cables may becoupled. Using two fiber optic cables per well allows for compensationdue to optical losses that occur in the wells and allows for betteraccuracy of measured temperature profiles.

The fiber optic temperature monitoring system may be used to detect thelocation of a breach or a potential breach in a frozen barrier. Thesearch for potential breaches may be performed at scheduled intervals,for example, every two or three months. To determine the location of thebreach or potential breach, flow of formation refrigerant to the freezewells of interest is stopped. In some embodiments, the flow of formationrefrigerant to all of the freeze wells is stopped. The rise in thetemperature profiles, as well as the rate of change of the temperatureprofiles, provided by the fiber optic temperature monitoring system foreach freeze well can be used to determine the location of any breachesor hot spots in the low temperature zone maintained by the freeze wells.The temperature profile monitored by the fiber optic temperaturemonitoring system for the two freeze wells closest to the hot spot orfluid flow will show the quickest and greatest rise in temperature. Atemperature change of a few degrees Centigrade in the temperatureprofiles of the freeze wells closest to a troubled area may besufficient to isolate the location of the trouble area. The shut downtime of flow of circulation fluid in the freeze wells of interest neededto detect breaches, potential breaches, and hot spots may be on theorder of a few hours or days, depending on the well spacing and theamount of fluid flow affecting the low temperature zone.

Fiber optic temperature monitoring systems may also be used to monitortemperatures in heated portions of the formation during in situ heattreatment processes. The fiber of a fiber optic cable used in the heatedportion of the formation may be clad with a reflective material tofacilitate retention of a signal or signals transmitted down the fiber.In some embodiments, the fiber is clad with gold, copper, nickel,aluminum and/or alloys thereof. The cladding may be formed of a materialthat is able to withstand chemical and temperature conditions in theheated portion of the formation. For example, gold cladding may allow anoptical sensor to be used up to temperatures of 700° C. In someembodiments, the fiber is clad with aluminum. The fiber may be dipped inor run through a bath of liquid aluminum. The clad fiber may then beallowed to cool to secure the aluminum to the fiber. The gold oraluminum cladding may reduce hydrogen darkening of the optical fiber.

A potential source of heat loss from the heated formation is due toreflux in wells. Refluxing occurs when vapors condense in a well andflow into a portion of the well adjacent to the heated portion of theformation. Vapors may condense in the well adjacent to the overburden ofthe formation to form condensed fluid. Condensed fluid flowing into thewell adjacent to the heated formation absorbs heat from the formation.Heat absorbed by condensed fluids cools the formation and necessitatesadditional energy input into the formation to maintain the formation ata desired temperature. Some fluids that condense in the overburden andflow into the portion of the well adjacent to the heated formation mayreact to produce undesired compounds and/or coke. Inhibiting fluids fromrefluxing may significantly improve the thermal efficiency of the insitu heat treatment system and/or the quality of the product producedfrom the in situ heat treatment system.

For some well embodiments, the portion of the well adjacent to theoverburden section of the formation is cemented to the formation. Insome well embodiments, the well includes packing material placed nearthe transition from the heated section of the formation to theoverburden. The packing material inhibits formation fluid from passingfrom the heated section of the formation into the section of thewellbore adjacent to the overburden. Cables, conduits, devices, and/orinstruments may pass through the packing material, but the packingmaterial inhibits formation fluid from passing up the wellbore adjacentto the overburden section of the formation.

In some embodiments, one or more baffle systems may be placed in thewellbores to inhibit reflux. The baffle systems may be obstructions tofluid flow into the heated portion of the formation. In someembodiments, refluxing fluid may revaporize on the baffle system beforecoming into contact with the heated portion of the formation.

In some embodiments, a gas may be introduced into the formation throughwellbores to inhibit reflux in the wellbores. In some embodiments, gasmay be introduced into wellbores that include baffle systems to inhibitreflux of fluid in the wellbores. The gas may be carbon dioxide,methane, nitrogen or other desired gas. In some embodiments, theintroduction of gas may be used in conjunction with one or more bafflesystems in the wellbores. The introduced gas may enhance heat exchangeat the baffle systems to help maintain top portions of the bafflesystems colder than the lower portions of the baffle systems.

The flow of production fluid up the well to the surface is desired forsome types of wells, especially for production wells. Flow of productionfluid up the well is also desirable for some heater wells that are usedto control pressure in the formation. The overburden, or a conduit inthe well used to transport formation fluid from the heated portion ofthe formation to the surface, may be heated to inhibit condensation onor in the conduit. Providing heat in the overburden, however, may becostly and/or may lead to increased cracking or coking of formationfluid as the formation fluid is being produced from the formation.

To avoid the need to heat the overburden or to heat the conduit passingthrough the overburden, one or more diverters may be placed in thewellbore to inhibit fluid from refluxing into the wellbore adjacent tothe heated portion of the formation. In some embodiments, the diverterretains fluid above the heated portion of the formation. Fluids retainedin the diverter may be removed from the diverter using a pump, gaslifting, and/or other fluid removal technique. In certain embodiments,two or more diverters that retain fluid above the heated portion of theformation may be located in the production well. Two or more divertersprovide a simple way of separating initial fractions of condensed fluidproduced from the in situ heat treatment system. A pump may be placed ineach of the diverters to remove condensed fluid from the diverters.

In some embodiments, the diverter directs fluid to a sump below theheated portion of the formation. An inlet for a lift system may belocated in the sump. In some embodiments, the intake of the lift systemis located in casing in the sump. In some embodiments, the intake of thelift system is located in an open wellbore. The sump is below the heatedportion of the formation. The intake of the pump may be located 1 m, 5m, 10 m, 20 m or more below the deepest heater used to heat the heatedportion of the formation. The sump may be at a cooler temperature thanthe heated portion of the formation. The sump may be more than 10° C.,more than 50° C., more than 75° C., or more than 100° C. below thetemperature of the heated portion of the formation. A portion of thefluid entering the sump may be liquid. A portion of the fluid enteringthe sump may condense within the sump. The lift system moves the fluidin the sump to the surface.

Production well lift systems may be used to efficiently transportformation fluid from the bottom of the production wells to the surface.Production well lift systems may provide and maintain the maximumrequired well drawdown (minimum reservoir producing pressure) andproducing rates. The production well lift systems may operateefficiently over a wide range of high temperature/multiphase fluids(gas/vapor/steam/water/hydrocarbon liquids) and production ratesexpected during the life of a typical project. Production well liftsystems may include dual concentric rod pump lift systems, chamber liftsystems and other types of lift systems.

Temperature limited heaters may be in configurations and/or may includematerials that provide automatic temperature limiting properties for theheater at certain temperatures. In certain embodiments, ferromagneticmaterials are used in temperature limited heaters. Ferromagneticmaterial may self-limit temperature at or near the Curie temperature ofthe material and/or the phase transformation temperature range toprovide a reduced amount of heat when a time-varying current is appliedto the material. In certain embodiments, the ferromagnetic materialself-limits temperature of the temperature limited heater at a selectedtemperature that is approximately the Curie temperature and/or in thephase transformation temperature range. In certain embodiments, theselected temperature is within about 35° C., within about 25° C., withinabout 20° C., or within about 10° C. of the Curie temperature and/or thephase transformation temperature range. In certain embodiments,ferromagnetic materials are coupled with other materials (for example,highly conductive materials, high strength materials, corrosionresistant materials, or combinations thereof) to provide variouselectrical and/or mechanical properties. Some parts of the temperaturelimited heater may have a lower resistance (caused by differentgeometries and/or by using different ferromagnetic and/ornon-ferromagnetic materials) than other parts of the temperature limitedheater. Having parts of the temperature limited heater with variousmaterials and/or dimensions allows for tailoring the desired heat outputfrom each part of the heater.

Temperature limited heaters may be more reliable than other heaters.Temperature limited heaters may be less apt to break down or fail due tohot spots in the formation. In some embodiments, temperature limitedheaters allow for substantially uniform heating of the formation. Insome embodiments, temperature limited heaters are able to heat theformation more efficiently by operating at a higher average heat outputalong the entire length of the heater. The temperature limited heateroperates at the higher average heat output along the entire length ofthe heater because power to the heater does not have to be reduced tothe entire heater, as is the case with typical constant wattage heaters,if a temperature along any point of the heater exceeds, or is about toexceed, a maximum operating temperature of the heater. Heat output fromportions of a temperature limited heater approaching a Curie temperatureand/or the phase transformation temperature range of the heaterautomatically reduces without controlled adjustment of the time-varyingcurrent applied to the heater. The heat output automatically reduces dueto changes in electrical properties (for example, electrical resistance)of portions of the temperature limited heater. Thus, more power issupplied by the temperature limited heater during a greater portion of aheating process.

In certain embodiments, the system including temperature limited heatersinitially provides a first heat output and then provides a reduced(second heat output) heat output, near, at, or above the Curietemperature and/or the phase transformation temperature range of anelectrically resistive portion of the heater when the temperaturelimited heater is energized by a time-varying current. The first heatoutput is the heat output at temperatures below which the temperaturelimited heater begins to self-limit. In some embodiments, the first heatoutput is the heat output at a temperature about 50° C., about 75° C.,about 100° C., or about 125° C. below the Curie temperature and/or thephase transformation temperature range of the ferromagnetic material inthe temperature limited heater.

The temperature limited heater may be energized by time-varying current(alternating current or modulated direct current) supplied at thewellhead. The wellhead may include a power source and other components(for example, modulation components, transformers, and/or capacitors)used in supplying power to the temperature limited heater. Thetemperature limited heater may be one of many heaters used to heat aportion of the formation.

In certain embodiments, the temperature limited heater includes aconductor that operates as a skin effect or proximity effect heater whentime-varying current is applied to the conductor. The skin effect limitsthe depth of current penetration into the interior of the conductor. Forferromagnetic materials, the skin effect is dominated by the magneticpermeability of the conductor. The relative magnetic permeability offerromagnetic materials is typically between 10 and 1000 (for example,the relative magnetic permeability of ferromagnetic materials istypically at least 10 and may be at least 50, 100, 500, 1000 orgreater). As the temperature of the ferromagnetic material is raisedabove the Curie temperature, or the phase transformation temperaturerange, and/or as the applied electrical current is increased, themagnetic permeability of the ferromagnetic material decreasessubstantially and the skin depth expands rapidly (for example, the skindepth expands as the inverse square root of the magnetic permeability).The reduction in magnetic permeability results in a decrease in the ACor modulated DC resistance of the conductor near, at, or above the Curietemperature, the phase transformation temperature range, and/or as theapplied electrical current is increased. When the temperature limitedheater is powered by a substantially constant current source, portionsof the heater that approach, reach, or are above the Curie temperatureand/or the phase transformation temperature range may have reduced heatdissipation. Sections of the temperature limited heater that are not ator near the Curie temperature and/or the phase transformationtemperature range may be dominated by skin effect heating that allowsthe heater to have high heat dissipation due to a higher resistive load.

Curie temperature heaters have been used in soldering equipment, heatersfor medical applications, and heating elements for ovens (for example,pizza ovens). Some of these uses are disclosed in U.S. Pat. Nos.5,579,575 to Lamome et al.; 5,065,501 to Henschen et al.; and 5,512,732to Yagnik et al., all of which are incorporated by reference as if fullyset forth herein. U.S. Pat. No. 4,849,611 to Whitney et al., which isincorporated by reference as if fully set forth herein, describes aplurality of discrete, spaced-apart heating units including a reactivecomponent, a resistive heating component, and a temperature responsivecomponent.

An advantage of using the temperature limited heater to heathydrocarbons in the formation is that the conductor is chosen to have aCurie temperature and/or a phase transformation temperature range in adesired range of temperature operation. Operation within the desiredoperating temperature range allows substantial heat injection into theformation while maintaining the temperature of the temperature limitedheater, and other equipment, below design limit temperatures. Designlimit temperatures are temperatures at which properties such ascorrosion, creep, and/or deformation are adversely affected. Thetemperature limiting properties of the temperature limited heaterinhibit overheating or burnout of the heater adjacent to low thermalconductivity “hot spots” in the formation. In some embodiments, thetemperature limited heater is able to lower or control heat outputand/or withstand heat at temperatures above 25° C., 37° C., 100° C.,250° C., 500° C., 700° C., 800° C., 900° C., or higher up to 1131° C.,depending on the materials used in the heater.

The temperature limited heater allows for more heat injection into theformation than constant wattage heaters because the energy input intothe temperature limited heater does not have to be limited toaccommodate low thermal conductivity regions adjacent to the heater. Forexample, in Green River oil shale there is a difference of at least afactor of 3 in the thermal conductivity of the lowest richness oil shalelayers and the highest richness oil shale layers. When heating such aformation, substantially more heat is transferred to the formation withthe temperature limited heater than with the conventional heater that islimited by the temperature at low thermal conductivity layers. The heatoutput along the entire length of the conventional heater needs toaccommodate the low thermal conductivity layers so that the heater doesnot overheat at the low thermal conductivity layers and burn out. Theheat output adjacent to the low thermal conductivity layers that are athigh temperature will reduce for the temperature limited heater, but theremaining portions of the temperature limited heater that are not athigh temperature will still provide high heat output. Because heatersfor heating hydrocarbon formations typically have long lengths (forexample, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10km), the majority of the length of the temperature limited heater may beoperating below the Curie temperature and/or the phase transformationtemperature range while only a few portions are at or near the Curietemperature and/or the phase transformation temperature range of thetemperature limited heater.

The use of temperature limited heaters allows for efficient transfer ofheat to the formation. Efficient transfer of heat allows for reductionin time needed to heat the formation to a desired temperature. Forexample, in Green River oil shale, pyrolysis typically requires 9.5years to 10 years of heating when using a 12 m heater well spacing withconventional constant wattage heaters. For the same heater spacing,temperature limited heaters may allow a larger average heat output whilemaintaining heater equipment temperatures below equipment design limittemperatures. Pyrolysis in the formation may occur at an earlier timewith the larger average heat output provided by temperature limitedheaters than the lower average heat output provided by constant wattageheaters. For example, in Green River oil shale, pyrolysis may occur in 5years using temperature limited heaters with a 12 m heater well spacing.Temperature limited heaters counteract hot spots due to inaccurate wellspacing or drilling where heater wells come too close together. Incertain embodiments, temperature limited heaters allow for increasedpower output over time for heater wells that have been spaced too farapart, or limit power output for heater wells that are spaced too closetogether. Temperature limited heaters also supply more power in regionsadjacent the overburden and underburden to compensate for temperaturelosses in these regions.

Temperature limited heaters may be advantageously used in many types offormations. For example, in tar sands formations or relatively permeableformations containing heavy hydrocarbons, temperature limited heatersmay be used to provide a controllable low temperature output forreducing the viscosity of fluids, mobilizing fluids, and/or enhancingthe radial flow of fluids at or near the wellbore or in the formation.Temperature limited heaters may be used to inhibit excess coke formationdue to overheating of the near wellbore region of the formation.

The use of temperature limited heaters, in some embodiments, eliminatesor reduces the need for expensive temperature control circuitry. Forexample, the use of temperature limited heaters eliminates or reducesthe need to perform temperature logging and/or the need to use fixedthermocouples on the heaters to monitor potential overheating at hotspots.

In certain embodiments, phase transformation (for example, crystallinephase transformation or a change in the crystal structure) of materialsused in a temperature limited heater change the selected temperature atwhich the heater self-limits. Ferromagnetic material used in thetemperature limited heater may have a phase transformation (for example,a transformation from ferrite to austenite) that decreases the magneticpermeability of the ferromagnetic material. This reduction in magneticpermeability is similar to reduction in magnetic permeability due to themagnetic transition of the ferromagnetic material at the Curietemperature. The Curie temperature is the magnetic transitiontemperature of the ferrite phase of the ferromagnetic material. Thereduction in magnetic permeability results in a decrease in the AC ormodulated DC resistance of the temperature limited heater near, at, orabove the temperature of the phase transformation and/or the Curietemperature of the ferromagnetic material.

The phase transformation of the ferromagnetic material may occur over atemperature range. The temperature range of the phase transformationdepends on the ferromagnetic material and may vary, for example, over arange of about 5° C. to a range of about 200° C. Because the phasetransformation takes place over a temperature range, the reduction inthe magnetic permeability due to the phase transformation takes placeover the temperature range. The reduction in magnetic permeability mayalso occur hysteretically over the temperature range of the phasetransformation. In some embodiments, the phase transformation back tothe lower temperature phase of the ferromagnetic material is slower thanthe phase transformation to the higher temperature phase (for example,the transition from austenite back to ferrite is slower than thetransition from ferrite to austenite). The slower phase transformationback to the lower temperature phase may cause hysteretic operation ofthe heater at or near the phase transformation temperature range thatallows the heater to slowly increase to higher resistance after theresistance of the heater reduces due to high temperature.

In some embodiments, the phase transformation temperature range overlapswith the reduction in the magnetic permeability when the temperatureapproaches the Curie temperature of the ferromagnetic material. Theoverlap may produce a faster drop in electrical resistance versustemperature than if the reduction in magnetic permeability is solely dueto the temperature approaching the Curie temperature. The overlap mayalso produce hysteretic behavior of the temperature limited heater nearthe Curie temperature and/or in the phase transformation temperaturerange.

In certain embodiments, the hysteretic operation due to the phasetransformation is a smoother transition than the reduction in magneticpermeability due to magnetic transition at the Curie temperature. Thesmoother transition may be easier to control (for example, electricalcontrol using a process control device that interacts with the powersupply) than the sharper transition at the Curie temperature. In someembodiments, the Curie temperature is located inside the phasetransformation range for selected metallurgies used in temperaturelimited heaters. This phenomenon provides temperature limited heaterswith the smooth transition properties of the phase transformation inaddition to a sharp and definite transition due to the reduction inmagnetic properties at the Curie temperature. Such temperature limitedheaters may be easy to control (due to the phase transformation) whileproviding finite temperature limits (due to the sharp Curie temperaturetransition). Using the phase transformation temperature range instead ofand/or in addition to the Curie temperature in temperature limitedheaters increases the number and range of metallurgies that may be usedfor temperature limited heaters.

In certain embodiments, alloy additions are made to the ferromagneticmaterial to adjust the temperature range of the phase transformation.For example, adding carbon to the ferromagnetic material may increasethe phase transformation temperature range and lower the onsettemperature of the phase transformation. Adding titanium to theferromagnetic material may increase the onset temperature of the phasetransformation and decrease the phase transformation temperature range.Alloy compositions may be adjusted to provide desired Curie temperatureand phase transformation properties for the ferromagnetic material. Thealloy composition of the ferromagnetic material may be chosen based ondesired properties for the ferromagnetic material (such as, but notlimited to, magnetic permeability transition temperature or temperaturerange, resistance versus temperature profile, or power output). Additionof titanium may allow higher Curie temperatures to be obtained whenadding cobalt to 410 stainless steel by raising the ferrite to austenitephase transformation temperature range to a temperature range that isabove, or well above, the Curie temperature of the ferromagneticmaterial.

In some embodiments, temperature limited heaters are more economical tomanufacture or make than standard heaters. Typical ferromagneticmaterials include iron, carbon steel, or ferritic stainless steel. Suchmaterials are inexpensive as compared to nickel-based heating alloys(such as nichrome, Kanthal™ (Bulten-Kanthal AB, Sweden), and/or LOHM™(Driver-Harris Company, Harrison, N.J., U.S.A.)) typically used ininsulated conductor (mineral insulated cable) heaters. In one embodimentof the temperature limited heater, the temperature limited heater ismanufactured in continuous lengths as an insulated conductor heater tolower costs and improve reliability.

In some embodiments, the temperature limited heater is placed in theheater well using a coiled tubing rig. A heater that can be coiled on aspool may be manufactured by using metal such as ferritic stainlesssteel (for example, 409 stainless steel) that is welded using electricalresistance welding (ERW). U.S. Pat. No. 7,032,809 to Hopkins, which isincorporated by reference as if fully set forth herein, describesforming seam-welded pipe. To form a heater section, a metal strip from aroll is passed through a former where it is shaped into a tubular andthen longitudinally welded using ERW.

FIG. 18 depicts an embodiment of a device for longitudinal welding(seam-welding) of a tubular using ERW. Metal strip 474 is shaped intotubular form as it passes through ERW coil 476. Metal strip 474 is thenwelded into a tubular inside shield 478. As metal strip 474 is joinedinside shield 478, inert gas (for example, argon or another suitablewelding gas) is provided inside the forming tubular by gas inlets 480.Flushing the tubular with inert gas inhibits oxidation of the tubular asit is formed. Shield 478 may have window 482. Window 482 allows anoperator to visually inspect the welding process. Tubular 484 is formedby the welding process.

In some embodiments, a composite tubular may be formed from theseam-welded tubular. The seam-welded tubular is passed through a secondformer where a conductive strip (for example, a copper strip) isapplied, drawn down tightly on the tubular through a die, andlongitudinally welded using ERW. A sheath may be formed bylongitudinally welding a support material (for example, steel such as347H or 347HH) over the conductive strip material. The support materialmay be a strip rolled over the conductive strip material. An overburdensection of the heater may be formed in a similar manner.

In certain embodiments, the overburden section uses a non-ferromagneticmaterial such as 304 stainless steel or 316 stainless steel instead of aferromagnetic material. The heater section and overburden section may becoupled using standard techniques such as butt welding using an orbitalwelder. In some embodiments, the overburden section material (thenon-ferromagnetic material) may be pre-welded to the ferromagneticmaterial before rolling. The pre-welding may eliminate the need for aseparate coupling step (for example, butt welding). In an embodiment, aflexible cable (for example, a furnace cable such as a MGT 1000 furnacecable) may be pulled through the center after forming the tubularheater. An end bushing on the flexible cable may be welded to thetubular heater to provide an electrical current return path. The tubularheater, including the flexible cable, may be coiled onto a spool beforeinstallation into a heater well. In an embodiment, the temperaturelimited heater is installed using the coiled tubing rig. The coiledtubing rig may place the temperature limited heater in a deformationresistant container in the formation. The deformation resistantcontainer may be placed in the heater well using conventional methods.

Temperature limited heaters may be used for heating hydrocarbonformations including, but not limited to, oil shale formations, coalformations, tar sands formations, and formations with heavy viscousoils. Temperature limited heaters may also be used in the field ofenvironmental remediation to vaporize or destroy soil contaminants.Embodiments of temperature limited heaters may be used to heat fluids ina wellbore or sub-sea pipeline to inhibit deposition of paraffin orvarious hydrates. In some embodiments, a temperature limited heater isused for solution mining a subsurface formation (for example, an oilshale or a coal formation). In certain embodiments, a fluid (forexample, molten salt) is placed in a wellbore and heated with atemperature limited heater to inhibit deformation and/or collapse of thewellbore. In some embodiments, the temperature limited heater isattached to a sucker rod in the wellbore or is part of the sucker roditself. In some embodiments, temperature limited heaters are used toheat a near wellbore region to reduce near wellbore oil viscosity duringproduction of high viscosity crude oils and during transport of highviscosity oils to the surface. In some embodiments, a temperaturelimited heater enables gas lifting of a viscous oil by lowering theviscosity of the oil without coking the oil. Temperature limited heatersmay be used in sulfur transfer lines to maintain temperatures betweenabout 110° C. and about 130° C.

The ferromagnetic alloy or ferromagnetic alloys used in the temperaturelimited heater determine the Curie temperature of the heater. Curietemperature data for various metals is listed in “American Institute ofPhysics Handbook,” Second Edition, McGraw-Hill, pages 5-170 through5-176. Ferromagnetic conductors may include one or more of theferromagnetic elements (iron, cobalt, and nickel) and/or alloys of theseelements. In some embodiments, ferromagnetic conductors includeiron-chromium (Fe—Cr) alloys that contain tungsten (W) (for example,HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys thatcontain chromium (for example, Fe—Cr alloys, Fe—Cr—W alloys, Fe—Cr—V(vanadium) alloys, and Fe—Cr—Nb (Niobium) alloys). Of the three mainferromagnetic elements, iron has a Curie temperature of approximately770° C.; cobalt (Co) has a Curie temperature of approximately 1131° C.;and nickel has a Curie temperature of approximately 358° C. Aniron-cobalt alloy has a Curie temperature higher than the Curietemperature of iron. For example, iron-cobalt alloy with 2% by weightcobalt has a Curie temperature of approximately 800° C.; iron-cobaltalloy with 12% by weight cobalt has a Curie temperature of approximately900° C.; and iron-cobalt alloy with 20% by weight cobalt has a Curietemperature of approximately 950° C. Iron-nickel alloy has a Curietemperature lower than the Curie temperature of iron. For example,iron-nickel alloy with 20% by weight nickel has a Curie temperature ofapproximately 720° C., and iron-nickel alloy with 60% by weight nickelhas a Curie temperature of approximately 560° C.

Some non-ferromagnetic elements used as alloys raise the Curietemperature of iron. For example, an iron-vanadium alloy with 5.9% byweight vanadium has a Curie temperature of approximately 815° C. Othernon-ferromagnetic elements (for example, carbon, aluminum, copper,silicon, and/or chromium) may be alloyed with iron or otherferromagnetic materials to lower the Curie temperature.Non-ferromagnetic materials that raise the Curie temperature may becombined with non-ferromagnetic materials that lower the Curietemperature and alloyed with iron or other ferromagnetic materials toproduce a material with a desired Curie temperature and other desiredphysical and/or chemical properties. In some embodiments, the Curietemperature material is a ferrite such as NiFe2O4. In other embodiments,the Curie temperature material is a binary compound such as FeNi3 orFe3Al.

In some embodiments, the improved alloy includes carbon, cobalt, iron,manganese, silicon, or mixtures thereof. In certain embodiments, theimproved alloy includes, by weight: about 0.1% to about 10% cobalt;about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with thebalance being iron. In certain embodiments, the improved alloy includes,by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5%manganese, about 0.5% silicon, with the balance being iron.

In some embodiments, the improved alloy includes chromium, carbon,cobalt, iron, manganese, silicon, titanium, vanadium, or mixturesthereof. In certain embodiments, the improved alloy includes, by weight:about 5% to about 20% cobalt, about 0.1% carbon, about 0.5% manganese,about 0.5% silicon, about 0.1% to about 2% vanadium with the balancebeing iron. In some embodiments, the improved alloy includes, by weight:about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% toabout 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 2%vanadium, above 0% to about 1% titanium, with the balance being iron. Insome embodiments, the improved alloy includes, by weight: about 12%chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about0.5% manganese, above 0% to about 2% vanadium, above 0% to about 1%titanium, with the balance being iron. In some embodiments, the improvedalloy includes, by weight: about 12% chromium, about 0.1% carbon, about0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2%vanadium, with the balance being iron. In certain embodiments, theimproved alloy includes, by weight: about 12% chromium, about 0.1%carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0%to about 15% cobalt, above 0% to about 1% titanium, with the balancebeing iron. In certain embodiments, the improved alloy includes, byweight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about0.1% to about 0.5% manganese, above 0% to about 15% cobalt, with thebalance being iron. The addition of vanadium may allow for use of higheramounts of cobalt in the improved alloy.

Certain embodiments of temperature limited heaters may include more thanone ferromagnetic material. Such embodiments are within the scope ofembodiments described herein if any conditions described herein apply toat least one of the ferromagnetic materials in the temperature limitedheater.

Ferromagnetic properties generally decay as the Curie temperature and/orthe phase transformation temperature range is approached. The “Handbookof Electrical Heating for Industry” by C. James Erickson (IEEE Press,1995) shows a typical curve for 1% carbon steel (steel with 1% carbon byweight). The loss of magnetic permeability starts at temperatures above650° C. and tends to be complete when temperatures exceed 730° C. Thus,the self-limiting temperature may be somewhat below the actual Curietemperature and/or the phase transformation temperature range of theferromagnetic conductor. The skin depth for current flow in 1% carbonsteel is 0.132 cm at room temperature and increases to 0.445 cm at 720°C. From 720° C. to 730° C., the skin depth sharply increases to over 2.5cm. Thus, a temperature limited heater embodiment using 1% carbon steelbegins to self-limit between 650° C. and 730° C.

Skin depth generally defines an effective penetration depth oftime-varying current into the conductive material. In general, currentdensity decreases exponentially with distance from an outer surface tothe center along the radius of the conductor. The depth at which thecurrent density is approximately 1/e of the surface current density iscalled the skin depth. For a solid cylindrical rod with a diameter muchgreater than the penetration depth, or for hollow cylinders with a wallthickness exceeding the penetration depth, the skin depth, δ, is:

δ=1981.5*(ρ/(μ*f))^(1/2);  (EQN. 4)

in which: δ=skin depth in inches;

-   -   ρ=resistivity at operating temperature (ohm-cm);    -   μ=relative magnetic permeability; and    -   f=frequency (Hz).

EQN. 4 is obtained from “Handbook of Electrical Heating for Industry” byC. James Erickson (IEEE Press, 1995). For most metals, resistivity (ρ)increases with temperature. The relative magnetic permeability generallyvaries with temperature and with current. Additional equations may beused to assess the variance of magnetic permeability and/or skin depthon both temperature and/or current. The dependence of μ on currentarises from the dependence of μ on the electromagnetic field.

Materials used in the temperature limited heater may be selected toprovide a desired turndown ratio. Turndown ratios of at least 1.1:1,2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperaturelimited heaters. Larger turndown ratios may also be used. A selectedturndown ratio may depend on a number of factors including, but notlimited to, the type of formation in which the temperature limitedheater is located (for example, a higher turndown ratio may be used foran oil shale formation with large variations in thermal conductivitybetween rich and lean oil shale layers) and/or a temperature limit ofmaterials used in the wellbore (for example, temperature limits ofheater materials). In some embodiments, the turndown ratio is increasedby coupling additional copper or another good electrical conductor tothe ferromagnetic material (for example, adding copper to lower theresistance above the Curie temperature and/or the phase transformationtemperature range).

The temperature limited heater may provide a maximum heat output (poweroutput) below the Curie temperature and/or the phase transformationtemperature range of the heater. In certain embodiments, the maximumheat output is at least 400 W/m (Watts per meter), 600 W/m, 700 W/m, 800W/m, or higher up to 2000 W/m. The temperature limited heater reducesthe amount of heat output by a section of the heater when thetemperature of the section of the heater approaches or is above theCurie temperature and/or the phase transformation temperature range. Thereduced amount of heat may be substantially less than the heat outputbelow the Curie temperature and/or the phase transformation temperaturerange. In some embodiments, the reduced amount of heat is at most 400W/m, 200 W/m, 100 W/m or may approach 0 W/m.

In certain embodiments, the temperature limited heater operatessubstantially independently of the thermal load on the heater in acertain operating temperature range. “Thermal load” is the rate thatheat is transferred from a heating system to its surroundings. It is tobe understood that the thermal load may vary with temperature of thesurroundings and/or the thermal conductivity of the surroundings. In anembodiment, the temperature limited heater operates at or above theCurie temperature and/or the phase transformation temperature range ofthe temperature limited heater such that the operating temperature ofthe heater increases at most by 3° C., 2° C., 1.5° C., 1° C., or 0.5° C.for a decrease in thermal load of 1 W/m proximate to a portion of theheater. In certain embodiments, the temperature limited heater operatesin such a manner at a relatively constant current.

The AC or modulated DC resistance and/or the heat output of thetemperature limited heater may decrease as the temperature approachesthe Curie temperature and/or the phase transformation temperature rangeand decrease sharply near or above the Curie temperature due to theCurie effect and/or phase transformation effect. In certain embodiments,the value of the electrical resistance or heat output above or near theCurie temperature and/or the phase transformation temperature range isat most one-half of the value of electrical resistance or heat output ata certain point below the Curie temperature and/or the phasetransformation temperature range. In some embodiments, the heat outputabove or near the Curie temperature and/or the phase transformationtemperature range is at most 90%, 70%, 50%, 30%, 20%, 10%, or less (downto 1%) of the heat output at a certain point below the Curie temperatureand/or the phase transformation temperature range (for example, 30° C.below the Curie temperature, 40° C. below the Curie temperature, 50° C.below the Curie temperature, or 100° C. below the Curie temperature). Incertain embodiments, the electrical resistance above or near the Curietemperature and/or the phase transformation temperature range decreasesto 80%, 70%, 60%, 50%, or less (down to 1%) of the electrical resistanceat a certain point below the Curie temperature and/or the phasetransformation temperature range (for example, 30° C. below the Curietemperature, 40° C. below the Curie temperature, 50° C. below the Curietemperature, or 100° C. below the Curie temperature).

In some embodiments, AC frequency is adjusted to change the skin depthof the ferromagnetic material. For example, the skin depth of 1% carbonsteel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and0.046 cm at 440 Hz. Since heater diameter is typically larger than twicethe skin depth, using a higher frequency (and thus a heater with asmaller diameter) reduces heater costs. For a fixed geometry, the higherfrequency results in a higher turndown ratio. The turndown ratio at ahigher frequency is calculated by multiplying the turndown ratio at alower frequency by the square root of the higher frequency divided bythe lower frequency. In some embodiments, a frequency between 100 Hz and1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used(for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, highfrequencies may be used. The frequencies may be greater than 1000 Hz.

To maintain a substantially constant skin depth until the Curietemperature and/or the phase transformation temperature range of thetemperature limited heater is reached, the heater may be operated at alower frequency when the heater is cold and operated at a higherfrequency when the heater is hot. Line frequency heating is generallyfavorable, however, because there is less need for expensive componentssuch as power supplies, transformers, or current modulators that alterfrequency. Line frequency is the frequency of a general supply ofcurrent. Line frequency is typically 60 Hz, but may be 50 Hz or anotherfrequency depending on the source for the supply of the current. Higherfrequencies may be produced using commercially available equipment suchas solid state variable frequency power supplies. Transformers thatconvert three-phase power to single-phase power with three times thefrequency are commercially available. For example, high voltagethree-phase power at 60 Hz may be transformed to single-phase power at180 Hz and at a lower voltage. Such transformers are less expensive andmore energy efficient than solid state variable frequency powersupplies. In certain embodiments, transformers that convert three-phasepower to single-phase power are used to increase the frequency of powersupplied to the temperature limited heater.

In certain embodiments, modulated DC (for example, chopped DC, waveformmodulated DC, or cycled DC) may be used for providing electrical powerto the temperature limited heater. A DC modulator or DC chopper may becoupled to a DC power supply to provide an output of modulated directcurrent. In some embodiments, the DC power supply may include means formodulating DC. One example of a DC modulator is a DC-to-DC convertersystem. DC-to-DC converter systems are generally known in the art. DC istypically modulated or chopped into a desired waveform. Waveforms for DCmodulation include, but are not limited to, square-wave, sinusoidal,deformed sinusoidal, deformed square-wave, triangular, and other regularor irregular waveforms.

The modulated DC waveform generally defines the frequency of themodulated DC. Thus, the modulated DC waveform may be selected to providea desired modulated DC frequency. The shape and/or the rate ofmodulation (such as the rate of chopping) of the modulated DC waveformmay be varied to vary the modulated DC frequency. DC may be modulated atfrequencies that are higher than generally available AC frequencies. Forexample, modulated DC may be provided at frequencies of at least 1000Hz. Increasing the frequency of supplied current to higher valuesadvantageously increases the turndown ratio of the temperature limitedheater.

In certain embodiments, the modulated DC waveform is adjusted or alteredto vary the modulated DC frequency. The DC modulator may be able toadjust or alter the modulated DC waveform at any time during use of thetemperature limited heater and at high currents or voltages. Thus,modulated DC provided to the temperature limited heater is not limitedto a single frequency or even a small set of frequency values. Waveformselection using the DC modulator typically allows for a wide range ofmodulated DC frequencies and for discrete control of the modulated DCfrequency. Thus, the modulated DC frequency is more easily set at adistinct value whereas AC frequency is generally limited to multiples ofthe line frequency. Discrete control of the modulated DC frequencyallows for more selective control over the turndown ratio of thetemperature limited heater. Being able to selectively control theturndown ratio of the temperature limited heater allows for a broaderrange of materials to be used in designing and constructing thetemperature limited heater.

In some embodiments, the modulated DC frequency or the AC frequency isadjusted to compensate for changes in properties (for example,subsurface conditions such as temperature or pressure) of thetemperature limited heater during use. The modulated DC frequency or theAC frequency provided to the temperature limited heater is varied basedon assessed downhole conditions. For example, as the temperature of thetemperature limited heater in the wellbore increases, it may beadvantageous to increase the frequency of the current provided to theheater, thus increasing the turndown ratio of the heater. In anembodiment, the downhole temperature of the temperature limited heaterin the wellbore is assessed.

In certain embodiments, the modulated DC frequency, or the AC frequency,is varied to adjust the turndown ratio of the temperature limitedheater. The turndown ratio may be adjusted to compensate for hot spotsoccurring along a length of the temperature limited heater. For example,the turndown ratio is increased because the temperature limited heateris getting too hot in certain locations. In some embodiments, themodulated DC frequency, or the AC frequency, are varied to adjust aturndown ratio without assessing a subsurface condition.

At or near the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic material, a relatively smallchange in voltage may cause a relatively large change in current to theload. The relatively small change in voltage may produce problems in thepower supplied to the temperature limited heater, especially at or nearthe Curie temperature and/or the phase transformation temperature range.The problems include, but are not limited to, reducing the power factor,tripping a circuit breaker, and/or blowing a fuse. In some cases,voltage changes may be caused by a change in the load of the temperaturelimited heater. In certain embodiments, an electrical current supply(for example, a supply of modulated DC or AC) provides a relativelyconstant amount of current that does not substantially vary with changesin load of the temperature limited heater. In an embodiment, theelectrical current supply provides an amount of electrical current thatremains within 15%, within 10%, within 5%, or within 2% of a selectedconstant current value when a load of the temperature limited heaterchanges.

Temperature limited heaters may generate an inductive load. Theinductive load is due to some applied electrical current being used bythe ferromagnetic material to generate a magnetic field in addition togenerating a resistive heat output. As downhole temperature changes inthe temperature limited heater, the inductive load of the heater changesdue to changes in the ferromagnetic properties of ferromagneticmaterials in the heater with temperature. The inductive load of thetemperature limited heater may cause a phase shift between the currentand the voltage applied to the heater.

A reduction in actual power applied to the temperature limited heatermay be caused by a time lag in the current waveform (for example, thecurrent has a phase shift relative to the voltage due to an inductiveload) and/or by distortions in the current waveform (for example,distortions in the current waveform caused by introduced harmonics dueto a non-linear load). Thus, it may take more current to apply aselected amount of power due to phase shifting or waveform distortion.The ratio of actual power applied and the apparent power that would havebeen transmitted if the same current were in phase and undistorted isthe power factor. The power factor is always less than or equal to 1.The power factor is 1 when there is no phase shift or distortion in thewaveform.

Actual power applied to a heater due to a phase shift may be describedby EQN. 5:

P=I×V×cos(θ);  (EQN. 5)

in which P is the actual power applied to a heater; I is the appliedcurrent; V is the applied voltage; and θ is the phase angle differencebetween voltage and current. Other phenomena such as waveform distortionmay contribute to further lowering of the power factor. If there is nodistortion in the waveform, then cos(θ) is equal to the power factor.

In certain embodiments, the temperature limited heater includes an innerconductor inside an outer conductor. The inner conductor and the outerconductor are radially disposed about a central axis. The inner andouter conductors may be separated by an insulation layer. In certainembodiments, the inner and outer conductors are coupled at the bottom ofthe temperature limited heater. Electrical current may flow into thetemperature limited heater through the inner conductor and returnthrough the outer conductor. One or both conductors may includeferromagnetic material.

The insulation layer may comprise an electrically insulating ceramicwith high thermal conductivity, such as magnesium oxide, aluminum oxide,silicon dioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. The insulating layer may be a compacted powder(for example, compacted ceramic powder). Compaction may improve thermalconductivity and provide better insulation resistance. For lowertemperature applications, polymer insulation made from, for example,fluoropolymers, polyimides, polyamides, and/or polyethylenes, may beused. In some embodiments, the polymer insulation is made ofperfluoroalkoxy (PFA) or polyetheretherketone (PEEK™ (Victrex Ltd,England)). The insulating layer may be chosen to be substantiallyinfrared transparent to aid heat transfer from the inner conductor tothe outer conductor. In an embodiment, the insulating layer istransparent quartz sand. The insulation layer may be air or anon-reactive gas such as helium, nitrogen, or sulfur hexafluoride. Ifthe insulation layer is air or a non-reactive gas, there may beinsulating spacers designed to inhibit electrical contact between theinner conductor and the outer conductor. The insulating spacers may bemade of, for example, high purity aluminum oxide or another thermallyconducting, electrically insulating material such as silicon nitride.The insulating spacers may be a fibrous ceramic material such as Nextel™312 (3M Corporation, St. Paul, Minn., U.S.A.), mica tape, or glassfiber. Ceramic material may be made of alumina, alumina-silicate,alumina-borosilicate, silicon nitride, boron nitride, or othermaterials.

The insulation layer may be flexible and/or substantially deformationtolerant. For example, if the insulation layer is a solid or compactedmaterial that substantially fills the space between the inner and outerconductors, the temperature limited heater may be flexible and/orsubstantially deformation tolerant. Forces on the outer conductor can betransmitted through the insulation layer to the solid inner conductor,which may resist crushing. Such a temperature limited heater may bebent, dog-legged, and spiraled without causing the outer conductor andthe inner conductor to electrically short to each other. Deformationtolerance may be important if the wellbore is likely to undergosubstantial deformation during heating of the formation.

In certain embodiments, an outermost layer of the temperature limitedheater (for example, the outer conductor) is chosen for corrosionresistance, yield strength, and/or creep resistance. In one embodiment,austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H,347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainlesssteels, or combinations thereof may be used in the outer conductor. Theoutermost layer may also include a clad conductor. For example, acorrosion resistant alloy such as 800H or 347H stainless steel may beclad for corrosion protection over a ferromagnetic carbon steel tubular.If high temperature strength is not required, the outermost layer may beconstructed from ferromagnetic metal with good corrosion resistance suchas one of the ferritic stainless steels. In one embodiment, a ferriticalloy of 82.3% by weight iron with 17.7% by weight chromium (Curietemperature of 678° C.) provides desired corrosion resistance.

The Metals Handbook, vol. 8, page 291 (American Society of Materials(ASM)) includes a graph of Curie temperature of iron-chromium alloysversus the amount of chromium in the alloys. In some temperature limitedheater embodiments, a separate support rod or tubular (made from 347Hstainless steel) is coupled to the temperature limited heater made froman iron-chromium alloy to provide yield strength and/or creepresistance. In certain embodiments, the support material and/or theferromagnetic material is selected to provide a 100,000 hourcreep-rupture strength of at least 20.7 MPa at 650° C. In someembodiments, the 100,000 hour creep-rupture strength is at least 13.8MPa at 650° C. or at least 6.9 MPa at 650° C. For example, 347H steelhas a favorable creep-rupture strength at or above 650° C. In someembodiments, the 100,000 hour creep-rupture strength ranges from 6.9 MPato 41.3 MPa or more for longer heaters and/or higher earth or fluidstresses.

In temperature limited heater embodiments with both an innerferromagnetic conductor and an outer ferromagnetic conductor, the skineffect current path occurs on the outside of the inner conductor and onthe inside of the outer conductor. Thus, the outside of the outerconductor may be clad with the corrosion resistant alloy, such asstainless steel, without affecting the skin effect current path on theinside of the outer conductor.

A ferromagnetic conductor with a thickness of at least the skin depth atthe Curie temperature and/or the phase transformation temperature rangeallows a substantial decrease in resistance of the ferromagneticmaterial as the skin depth increases sharply near the Curie temperatureand/or the phase transformation temperature range. In certainembodiments when the ferromagnetic conductor is not clad with a highlyconducting material such as copper, the thickness of the conductor maybe 1.5 times the skin depth near the Curie temperature and/or the phasetransformation temperature range, 3 times the skin depth near the Curietemperature and/or the phase transformation temperature range, or even10 or more times the skin depth near the Curie temperature and/or thephase transformation temperature range. If the ferromagnetic conductoris clad with copper, thickness of the ferromagnetic conductor may besubstantially the same as the skin depth near the Curie temperatureand/or the phase transformation temperature range. In some embodiments,the ferromagnetic conductor clad with copper has a thickness of at leastthree-fourths of the skin depth near the Curie temperature and/or thephase transformation temperature range.

In certain embodiments, the temperature limited heater includes acomposite conductor with a ferromagnetic tubular and anon-ferromagnetic, high electrical conductivity core. Thenon-ferromagnetic, high electrical conductivity core reduces a requireddiameter of the conductor. For example, the conductor may be composite1.19 cm diameter conductor with a core of 0.575 cm diameter copper cladwith a 0.298 cm thickness of ferritic stainless steel or carbon steelsurrounding the core. The core or non-ferromagnetic conductor may becopper or copper alloy. The core or non-ferromagnetic conductor may alsobe made of other metals that exhibit low electrical resistivity andrelative magnetic permeabilities near 1 (for example, substantiallynon-ferromagnetic materials such as aluminum and aluminum alloys,phosphor bronze, beryllium copper, and/or brass). A composite conductorallows the electrical resistance of the temperature limited heater todecrease more steeply near the Curie temperature and/or the phasetransformation temperature range. As the skin depth increases near theCurie temperature and/or the phase transformation temperature range toinclude the copper core, the electrical resistance decreases verysharply.

The composite conductor may increase the conductivity of the temperaturelimited heater and/or allow the heater to operate at lower voltages. Inan embodiment, the composite conductor exhibits a relatively flatresistance versus temperature profile at temperatures below a regionnear the Curie temperature and/or the phase transformation temperaturerange of the ferromagnetic conductor of the composite conductor. In someembodiments, the temperature limited heater exhibits a relatively flatresistance versus temperature profile between 100° C. and 750° C. orbetween 300° C. and 600° C. The relatively flat resistance versustemperature profile may also be exhibited in other temperature ranges byadjusting, for example, materials and/or the configuration of materialsin the temperature limited heater. In certain embodiments, the relativethickness of each material in the composite conductor is selected toproduce a desired resistivity versus temperature profile for thetemperature limited heater.

In certain embodiments, the relative thickness of each material in acomposite conductor is selected to produce a desired resistivity versustemperature profile for a temperature limited heater. In an embodiment,the composite conductor is an inner conductor surrounded by 0.127 cmthick magnesium oxide powder as an insulator. The outer conductor may be304H stainless steel with a wall thickness of 0.127 cm. The outsidediameter of the heater may be about 1.65 cm.

A composite conductor (for example, a composite inner conductor or acomposite outer conductor) may be manufactured by methods including, butnot limited to, coextrusion, roll forming, tight fit tubing (forexample, cooling the inner member and heating the outer member, theninserting the inner member in the outer member, followed by a drawingoperation and/or allowing the system to cool), explosive orelectromagnetic cladding, arc overlay welding, longitudinal stripwelding, plasma powder welding, billet coextrusion, electroplating,drawing, sputtering, plasma deposition, coextrusion casting, magneticforming, molten cylinder casting (of inner core material inside theouter or vice versa), insertion followed by welding or high temperaturebraising, shielded active gas welding (SAG), and/or insertion of aninner pipe in an outer pipe followed by mechanical expansion of theinner pipe by hydroforming or use of a pig to expand and swage the innerpipe against the outer pipe. In some embodiments, a ferromagneticconductor is braided over a non-ferromagnetic conductor. In certainembodiments, composite conductors are formed using methods similar tothose used for cladding (for example, cladding copper to steel). Ametallurgical bond between copper cladding and base ferromagneticmaterial may be advantageous. Composite conductors produced by acoextrusion process that forms a good metallurgical bond (for example, agood bond between copper and 446 stainless steel) may be provided byAnomet Products, Inc. (Shrewsbury, Mass., U.S.A.).

FIGS. 19-40 depict various embodiments of temperature limited heaters.One or more features of an embodiment of the temperature limited heaterdepicted in any of these figures may be combined with one or morefeatures of other embodiments of temperature limited heaters depicted inthese figures. In certain embodiments described herein, temperaturelimited heaters are dimensioned to operate at a frequency of 60 Hz AC.It is to be understood that dimensions of the temperature limited heatermay be adjusted from those described herein to operate in a similarmanner at other AC frequencies or with modulated DC current.

FIG. 19 depicts a cross-sectional representation of an embodiment of thetemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section. FIGS. 20 and 21depict transverse cross-sectional views of the embodiment shown in FIG.19. In one embodiment, ferromagnetic section 486 is used to provide heatto hydrocarbon layers in the formation. Non-ferromagnetic section 488 isused in the overburden of the formation. Non-ferromagnetic section 488provides little or no heat to the overburden, thus inhibiting heatlosses in the overburden and improving heater efficiency. Ferromagneticsection 486 includes a ferromagnetic material such as 409 stainlesssteel or 410 stainless steel. Ferromagnetic section 486 has a thicknessof 0.3 cm. Non-ferromagnetic section 488 is copper with a thickness of0.3 cm. Inner conductor 490 is copper. Inner conductor 490 has adiameter of 0.9 cm. Electrical insulator 500 is silicon nitride, boronnitride, magnesium oxide powder, or another suitable insulator material.Electrical insulator 500 has a thickness of 0.1 cm to 0.3 cm.

FIG. 22 depicts a cross-sectional representation of an embodiment of atemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section placed inside asheath. FIGS. 23, 24, and 25 depict transverse cross-sectional views ofthe embodiment shown in FIG. 22. Ferromagnetic section 486 is 410stainless steel with a thickness of 0.6 cm. Non-ferromagnetic section488 is copper with a thickness of 0.6 cm. Inner conductor 490 is copperwith a diameter of 0.9 cm. Outer conductor 502 includes ferromagneticmaterial. Outer conductor 502 provides some heat in the overburdensection of the heater. Providing some heat in the overburden inhibitscondensation or refluxing of fluids in the overburden. Outer conductor502 is 409, 410, or 446 stainless steel with an outer diameter of 3.0 cmand a thickness of 0.6 cm. Electrical insulator 500 includes compactedmagnesium oxide powder with a thickness of 0.3 cm. In some embodiments,electrical insulator 500 includes silicon nitride, boron nitride, orhexagonal type boron nitride. Conductive section 504 may couple innerconductor 490 with ferromagnetic section 486 and/or outer conductor 502.

FIG. 26A and FIG. 26B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor. Inner conductor 490 is a 1″ Schedule XXS 446 stainless steelpipe. In some embodiments, inner conductor 490 includes 409 stainlesssteel, 410 stainless steel, Invar 36, alloy 42-6, alloy 52, or otherferromagnetic materials. Inner conductor 490 has a diameter of 2.5 cm.Electrical insulator 500 includes compacted silicon nitride, boronnitride, or magnesium oxide powders; or polymers, Nextel ceramic fiber,mica, or glass fibers. Outer conductor 502 is copper or any othernon-ferromagnetic material, such as but not limited to copper alloys,aluminum and/or aluminum alloys. Outer conductor 502 is coupled tojacket 506. Jacket 506 is 304H, 316H, or 347H stainless steel. In thisembodiment, a majority of the heat is produced in inner conductor 490.

FIG. 27A and FIG. 27B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor and a non-ferromagnetic core. Inner conductor 490 may be madeof 446 stainless steel, 409 stainless steel, 410 stainless steel, carbonsteel, Armco ingot iron, iron-cobalt alloys, or other ferromagneticmaterials. Core 508 may be tightly bonded inside inner conductor 490.Core 508 is copper or other non-ferromagnetic material. In certainembodiments, core 508 is inserted as a tight fit inside inner conductor490 before a drawing operation. In some embodiments, core 508 and innerconductor 490 are coextrusion bonded. Outer conductor 502 is 347Hstainless steel. A drawing or rolling operation to compact electricalinsulator 500 (for example, compacted silicon nitride, boron nitride, ormagnesium oxide powder) may ensure good electrical contact between innerconductor 490 and core 508. In this embodiment, heat is producedprimarily in inner conductor 490 until the Curie temperature and/or thephase transformation temperature range is approached. Resistance thendecreases sharply as current penetrates core 508.

FIG. 28A and FIG. 28B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. Inner conductor 490 is nickel-clad copper. Electricalinsulator 500 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 502 is a 1″ Schedule XXS carbon steel pipe. In thisembodiment, heat is produced primarily in outer conductor 502, resultingin a small temperature differential across electrical insulator 500.

FIG. 29A and FIG. 29B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor that is clad with a corrosion resistant alloy. Inner conductor490 is copper. Outer conductor 502 is a 1″ Schedule XXS carbon steelpipe. Outer conductor 502 is coupled to jacket 506. Jacket 506 is madeof corrosion resistant material (for example, 347H stainless steel).Jacket 506 provides protection from corrosive fluids in the wellbore(for example, sulfidizing and carburizing gases). Heat is producedprimarily in outer conductor 502, resulting in a small temperaturedifferential across electrical insulator 500.

FIG. 30A and FIG. 30B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. The outer conductor is clad with a conductive layer and acorrosion resistant alloy. Inner conductor 490 is copper. Electricalinsulator 500 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 502 is a 1″ Schedule 80 446 stainless steel pipe. Outerconductor 502 is coupled to jacket 506. Jacket 506 is made fromcorrosion resistant material such as 347H stainless steel. In anembodiment, conductive layer 510 is placed between outer conductor 502and jacket 506. Conductive layer 510 is a copper layer. Heat is producedprimarily in outer conductor 502, resulting in a small temperaturedifferential across electrical insulator 500. Conductive layer 510allows a sharp decrease in the resistance of outer conductor 502 as theouter conductor approaches the Curie temperature and/or the phasetransformation temperature range. Jacket 506 provides protection fromcorrosive fluids in the wellbore.

In some embodiments, the conductor (for example, an inner conductor, anouter conductor, or a ferromagnetic conductor) is the compositeconductor that includes two or more different materials. In certainembodiments, the composite conductor includes two or more ferromagneticmaterials. In some embodiments, the composite ferromagnetic conductorincludes two or more radially disposed materials. In certainembodiments, the composite conductor includes a ferromagnetic conductorand a non-ferromagnetic conductor. In some embodiments, the compositeconductor includes the ferromagnetic conductor placed over anon-ferromagnetic core. Two or more materials may be used to obtain arelatively flat electrical resistivity versus temperature profile in atemperature region below the Curie temperature, and/or the phasetransformation temperature range, and/or a sharp decrease (a highturndown ratio) in the electrical resistivity at or near the Curietemperature and/or the phase transformation temperature range. In somecases, two or more materials are used to provide more than one Curietemperature and/or phase transformation temperature range for thetemperature limited heater.

The composite electrical conductor may be used as the conductor in anyelectrical heater embodiment described herein. For example, thecomposite conductor may be used as the conductor in aconductor-in-conduit heater or an insulated conductor heater. In certainembodiments, the composite conductor may be coupled to a support membersuch as a support conductor. The support member may be used to providesupport to the composite conductor so that the composite conductor isnot relied upon for strength at or near the Curie temperature and/or thephase transformation temperature range. The support member may be usefulfor heaters of lengths of at least 100 m. The support member may be anon-ferromagnetic member that has good high temperature creep strength.Examples of materials that are used for a support member include, butare not limited to, Haynes® 625 alloy and Haynes® HR120® alloy (HaynesInternational, Kokomo, Ind., U.S.A.), NF709, Incoloy® 800H alloy and347HP alloy (Allegheny Ludlum Corp., Pittsburgh, Pa., U.S.A.). In someembodiments, materials in a composite conductor are directly coupled(for example, brazed, metallurgically bonded, or swaged) to each otherand/or the support member. Using a support member may reduce the needfor the ferromagnetic member to provide support for the temperaturelimited heater, especially at or near the Curie temperature and/or thephase transformation temperature range. Thus, the temperature limitedheater may be designed with more flexibility in the selection offerromagnetic materials.

FIG. 31 depicts a cross-sectional representation of an embodiment of thecomposite conductor with the support member. Core 508 is surrounded byferromagnetic conductor 512 and support member 514. In some embodiments,core 508, ferromagnetic conductor 512, and support member 514 aredirectly coupled (for example, brazed together or metallurgically bondedtogether). In one embodiment, core 508 is copper, ferromagneticconductor 512 is 446 stainless steel, and support member 514 is 347Halloy. In certain embodiments, support member 514 is a Schedule 80 pipe.Support member 514 surrounds the composite conductor havingferromagnetic conductor 512 and core 508. Ferromagnetic conductor 512and core 508 may be joined to form the composite conductor by, forexample, a coextrusion process. For example, the composite conductor isa 1.9 cm outside diameter 446 stainless steel ferromagnetic conductorsurrounding a 0.95 cm diameter copper core.

In certain embodiments, the diameter of core 508 is adjusted relative toa constant outside diameter of ferromagnetic conductor 512 to adjust theturndown ratio of the temperature limited heater. For example, thediameter of core 508 may be increased to 1.14 cm while maintaining theoutside diameter of ferromagnetic conductor 512 at 1.9 cm to increasethe turndown ratio of the heater.

In some embodiments, conductors (for example, core 508 and ferromagneticconductor 512) in the composite conductor are separated by supportmember 514. FIG. 32 depicts a cross-sectional representation of anembodiment of the composite conductor with support member 514 separatingthe conductors. In one embodiment, core 508 is copper with a diameter of0.95 cm, support member 514 is 347H alloy with an outside diameter of1.9 cm, and ferromagnetic conductor 512 is 446 stainless steel with anoutside diameter of 2.7 cm. The support member depicted in FIG. 32 has alower creep strength relative to the support members depicted in FIG.31.

In certain embodiments, support member 514 is located inside thecomposite conductor. FIG. 33 depicts a cross-sectional representation ofan embodiment of the composite conductor surrounding support member 514.Support member 514 is made of 347H alloy. Inner conductor 490 is copper.Ferromagnetic conductor 512 is 446 stainless steel. In one embodiment,support member 514 is 1.25 cm diameter 347H alloy, inner conductor 490is 1.9 cm outside diameter copper, and ferromagnetic conductor 512 is2.7 cm outside diameter 446 stainless steel. The turndown ratio ishigher than the turndown ratio for the embodiments depicted in FIGS. 31,32, and 34 for the same outside diameter, but the creep strength islower.

In some embodiments, the thickness of inner conductor 490, which iscopper, is reduced and the thickness of support member 514 is increasedto increase the creep strength at the expense of reduced turndown ratio.For example, the diameter of support member 514 is increased to 1.6 cmwhile maintaining the outside diameter of inner conductor 490 at 1.9 cmto reduce the thickness of the conduit. This reduction in thickness ofinner conductor 490 results in a decreased turndown ratio relative tothe thicker inner conductor embodiment but an increased creep strength.

In one embodiment, support member 514 is a conduit (or pipe) insideinner conductor 490 and ferromagnetic conductor 512. FIG. 34 depicts across-sectional representation of an embodiment of the compositeconductor surrounding support member 514. In one embodiment, supportmember 514 is 347H alloy with a 0.63 cm diameter center hole. In someembodiments, support member 514 is a preformed conduit. In certainembodiments, support member 514 is formed by having a dissolvablematerial (for example, copper dissolvable by nitric acid) located insidethe support member during formation of the composite conductor. Thedissolvable material is dissolved to form the hole after the conductoris assembled. In an embodiment, support member 514 is 347H alloy with aninside diameter of 0.63 cm and an outside diameter of 1.6 cm, innerconductor 490 is copper with an outside diameter of 1.8 cm, andferromagnetic conductor 512 is 446 stainless steel with an outsidediameter of 2.7 cm.

In certain embodiments, the composite electrical conductor is used asthe conductor in the conductor-in-conduit heater. For example, thecomposite electrical conductor may be used as conductor 516 in FIG. 35

FIG. 35 depicts a cross-sectional representation of an embodiment of theconductor-in-conduit heater. Conductor 516 is disposed in conduit 518.Conductor 516 is a rod or conduit of electrically conductive material.Low resistance sections 520 are present at both ends of conductor 516 togenerate less heating in these sections. Low resistance section 520 isformed by having a greater cross-sectional area of conductor 516 in thatsection, or the sections are made of material having less resistance. Incertain embodiments, low resistance section 520 includes a lowresistance conductor coupled to conductor 516.

Conduit 518 is made of an electrically conductive material. Conduit 518is disposed in opening 522 in hydrocarbon layer 460. Opening 522 has adiameter that accommodates conduit 518.

Conductor 516 may be centered in conduit 518 by centralizers 524.Centralizers 524 electrically isolate conductor 516 from conduit 518.Centralizers 524 inhibit movement and properly locate conductor 516 inconduit 518. Centralizers 524 are made of ceramic material or acombination of ceramic and metallic materials. Centralizers 524 inhibitdeformation of conductor 516 in conduit 518. Centralizers 524 aretouching or spaced at intervals between approximately 0.1 m (meters) andapproximately 3 m or more along conductor 516.

A second low resistance section 520 of conductor 516 may coupleconductor 516 to wellhead 450, as depicted in FIG. 35. Electricalcurrent may be applied to conductor 516 from power cable 526 through lowresistance section 520 of conductor 516. Electrical current passes fromconductor 516 through sliding connector 528 to conduit 518. Conduit 518may be electrically insulated from overburden casing 530 and fromwellhead 450 to return electrical current to power cable 526. Heat maybe generated in conductor 516 and conduit 518. The generated heat mayradiate in conduit 518 and opening 522 to heat at least a portion ofhydrocarbon layer 460.

Overburden casing 530 may be disposed in overburden 458. Overburdencasing 530 is, in some embodiments, surrounded by materials (forexample, reinforcing material and/or cement) that inhibit heating ofoverburden 458. Low resistance section 520 of conductor 516 may beplaced in overburden casing 530. Low resistance section 520 of conductor516 is made of, for example, carbon steel. Low resistance section 520 ofconductor 516 may be centralized in overburden casing 530 usingcentralizers 524. Centralizers 524 are spaced at intervals ofapproximately 6 m to approximately 12 m or, for example, approximately 9m along low resistance section 520 of conductor 516. In a heaterembodiment, low resistance section 520 of conductor 516 is coupled toconductor 516 by one or more welds. In other heater embodiments, lowresistance sections are threaded, threaded and welded, or otherwisecoupled to the conductor. Low resistance section 520 generates little orno heat in overburden casing 530. Packing 532 may be placed betweenoverburden casing 530 and opening 522. Packing 532 may be used as a capat the junction of overburden 458 and hydrocarbon layer 460 to allowfilling of materials in the annulus between overburden casing 530 andopening 522. In some embodiments, packing 532 inhibits fluid fromflowing from opening 522 to surface 534.

FIG. 36 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source. Conduit 518 may be placed inopening 522 through overburden 458 such that a gap remains between theconduit and overburden casing 530. Fluids may be removed from opening522 through the gap between conduit 518 and overburden casing 530.Fluids may be removed from the gap through conduit 536. Conduit 518 andcomponents of the heat source included in the conduit that are coupledto wellhead 450 may be removed from opening 522 as a single unit. Theheat source may be removed as a single unit to be repaired, replaced,and/or used in another portion of the formation.

For a temperature limited heater in which the ferromagnetic conductorprovides a majority of the resistive heat output below the Curietemperature and/or the phase transformation temperature range, amajority of the current flows through material with highly non-linearfunctions of magnetic field (H) versus magnetic induction (B). Thesenon-linear functions may cause strong inductive effects and distortionthat lead to decreased power factor in the temperature limited heater attemperatures below the Curie temperature and/or the phase transformationtemperature range. These effects may render the electrical power supplyto the temperature limited heater difficult to control and may result inadditional current flow through surface and/or overburden power supplyconductors. Expensive and/or difficult to implement control systems suchas variable capacitors or modulated power supplies may be used tocompensate for these effects and to control temperature limited heaterswhere the majority of the resistive heat output is provided by currentflow through the ferromagnetic material.

In certain temperature limited heater embodiments, the ferromagneticconductor confines a majority of the flow of electrical current to anelectrical conductor coupled to the ferromagnetic conductor when thetemperature limited heater is below or near the Curie temperature and/orthe phase transformation temperature range of the ferromagneticconductor. The electrical conductor may be a sheath, jacket, supportmember, corrosion resistant member, or other electrically resistivemember. In some embodiments, the ferromagnetic conductor confines amajority of the flow of electrical current to the electrical conductorpositioned between an outermost layer and the ferromagnetic conductor.The ferromagnetic conductor is located in the cross section of thetemperature limited heater such that the magnetic properties of theferromagnetic conductor at or below the Curie temperature and/or thephase transformation temperature range of the ferromagnetic conductorconfine the majority of the flow of electrical current to the electricalconductor. The majority of the flow of electrical current is confined tothe electrical conductor due to the skin effect of the ferromagneticconductor. Thus, the majority of the current is flowing through materialwith substantially linear resistive properties throughout most of theoperating range of the heater.

In certain embodiments, the ferromagnetic conductor and the electricalconductor are located in the cross section of the temperature limitedheater so that the skin effect of the ferromagnetic material limits thepenetration depth of electrical current in the electrical conductor andthe ferromagnetic conductor at temperatures below the Curie temperatureand/or the phase transformation temperature range of the ferromagneticconductor. Thus, the electrical conductor provides a majority of theelectrically resistive heat output of the temperature limited heater attemperatures up to a temperature at or near the Curie temperature and/orthe phase transformation temperature range of the ferromagneticconductor. In certain embodiments, the dimensions of the electricalconductor may be chosen to provide desired heat output characteristics.

Because the majority of the current flows through the electricalconductor below the Curie temperature and/or the phase transformationtemperature range, the temperature limited heater has a resistanceversus temperature profile that at least partially reflects theresistance versus temperature profile of the material in the electricalconductor. Thus, the resistance versus temperature profile of thetemperature limited heater is substantially linear below the Curietemperature and/or the phase transformation temperature range of theferromagnetic conductor if the material in the electrical conductor hasa substantially linear resistance versus temperature profile. Forexample, the temperature limited heater in which the majority of thecurrent flows in the electrical conductor below the Curie temperatureand/or the phase transformation temperature range may have a resistanceversus temperature profile similar to the profile shown in FIG. 214. Theresistance of the temperature limited heater has little or no dependenceon the current flowing through the heater until the temperature nearsthe Curie temperature and/or the phase transformation temperature range.The majority of the current flows in the electrical conductor ratherthan the ferromagnetic conductor below the Curie temperature and/or thephase transformation temperature range.

Resistance versus temperature profiles for temperature limited heatersin which the majority of the current flows in the electrical conductoralso tend to exhibit sharper reductions in resistance near or at theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. For example, the reduction in resistanceshown in FIG. 214 is sharper than the reduction in resistance shown inFIG. 200. The sharper reductions in resistance near or at the Curietemperature and/or the phase transformation temperature range are easierto control than more gradual resistance reductions near the Curietemperature and/or the phase transformation temperature range becauselittle current is flowing through the ferromagnetic material.

In certain embodiments, the material and/or the dimensions of thematerial in the electrical conductor are selected so that thetemperature limited heater has a desired resistance versus temperatureprofile below the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor.

Temperature limited heaters in which the majority of the current flowsin the electrical conductor rather than the ferromagnetic conductorbelow the Curie temperature and/or the phase transformation temperaturerange are easier to predict and/or control. Behavior of temperaturelimited heaters in which the majority of the current flows in theelectrical conductor rather than the ferromagnetic conductor below theCurie temperature and/or the phase transformation temperature range maybe predicted by, for example, its resistance versus temperature profileand/or its power factor versus temperature profile. Resistance versustemperature profiles and/or power factor versus temperature profiles maybe assessed or predicted by, for example, experimental measurements thatassess the behavior of the temperature limited heater, analyticalequations that assess or predict the behavior of the temperature limitedheater, and/or simulations that assess or predict the behavior of thetemperature limited heater.

In certain embodiments, assessed or predicted behavior of thetemperature limited heater is used to control the temperature limitedheater. The temperature limited heater may be controlled based onmeasurements (assessments) of the resistance and/or the power factorduring operation of the heater. In some embodiments, the power, orcurrent, supplied to the temperature limited heater is controlled basedon assessment of the resistance and/or the power factor of the heaterduring operation of the heater and the comparison of this assessmentversus the predicted behavior of the heater. In certain embodiments, thetemperature limited heater is controlled without measurement of thetemperature of the heater or a temperature near the heater. Controllingthe temperature limited heater without temperature measurementeliminates operating costs associated with downhole temperaturemeasurement. Controlling the temperature limited heater based onassessment of the resistance and/or the power factor of the heater alsoreduces the time for making adjustments in the power or current suppliedto the heater compared to controlling the heater based on measuredtemperature.

As the temperature of the temperature limited heater approaches orexceeds the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor, reduction in theferromagnetic properties of the ferromagnetic conductor allowselectrical current to flow through a greater portion of the electricallyconducting cross section of the temperature limited heater. Thus, theelectrical resistance of the temperature limited heater is reduced andthe temperature limited heater automatically provides reduced heatoutput at or near the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor. In certainembodiments, a highly electrically conductive member is coupled to theferromagnetic conductor and the electrical conductor to reduce theelectrical resistance of the temperature limited heater at or above theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. The highly electrically conductive membermay be an inner conductor, a core, or another conductive member ofcopper, aluminum, nickel, or alloys thereof.

The ferromagnetic conductor that confines the majority of the flow ofelectrical current to the electrical conductor at temperatures below theCurie temperature and/or the phase transformation temperature range mayhave a relatively small cross section compared to the ferromagneticconductor in temperature limited heaters that use the ferromagneticconductor to provide the majority of resistive heat output up to or nearthe Curie temperature and/or the phase transformation temperature range.A temperature limited heater that uses the electrical conductor toprovide a majority of the resistive heat output below the Curietemperature and/or the phase transformation temperature range has lowmagnetic inductance at temperatures below the Curie temperature and/orthe phase transformation temperature range because less current isflowing through the ferromagnetic conductor as compared to thetemperature limited heater where the majority of the resistive heatoutput below the Curie temperature and/or the phase transformationtemperature range is provided by the ferromagnetic material. Magneticfield (H) at radius (r) of the ferromagnetic conductor is proportionalto the current (I) flowing through the ferromagnetic conductor and thecore divided by the radius, or:

H∝I/r.  (EQN. 6)

Since only a portion of the current flows through the ferromagneticconductor for a temperature limited heater that uses the outer conductorto provide a majority of the resistive heat output below the Curietemperature and/or the phase transformation temperature range, themagnetic field of the temperature limited heater may be significantlysmaller than the magnetic field of the temperature limited heater wherethe majority of the current flows through the ferromagnetic material.The relative magnetic permeability (μ) may be large for small magneticfields.

The skin depth (δ) of the ferromagnetic conductor is inverselyproportional to the square root of the relative magnetic permeability(μ):

δ∝(1/μ)^(1/2).  (EQN. 7)

Increasing the relative magnetic permeability decreases the skin depthof the ferromagnetic conductor. However, because only a portion of thecurrent flows through the ferromagnetic conductor for temperatures belowthe Curie temperature and/or the phase transformation temperature range,the radius (or thickness) of the ferromagnetic conductor may bedecreased for ferromagnetic materials with large relative magneticpermeabilities to compensate for the decreased skin depth while stillallowing the skin effect to limit the penetration depth of theelectrical current to the electrical conductor at temperatures below theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. The radius (thickness) of the ferromagneticconductor may be between 0.3 mm and 8 mm, between 0.3 mm and 2 mm, orbetween 2 mm and 4 mm depending on the relative magnetic permeability ofthe ferromagnetic conductor. Decreasing the thickness of theferromagnetic conductor decreases costs of manufacturing the temperaturelimited heater, as the cost of ferromagnetic material tends to be asignificant portion of the cost of the temperature limited heater.Increasing the relative magnetic permeability of the ferromagneticconductor provides a higher turndown ratio and a sharper decrease inelectrical resistance for the temperature limited heater at or near theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor.

Ferromagnetic materials (such as purified iron or iron-cobalt alloys)with high relative magnetic permeabilities (for example, at least 200,at least 1000, at least 1×104, or at least 1×105) and/or high Curietemperatures (for example, at least 600° C., at least 700° C., or atleast 800° C.) tend to have less corrosion resistance and/or lessmechanical strength at high temperatures. The electrical conductor mayprovide corrosion resistance and/or high mechanical strength at hightemperatures for the temperature limited heater. Thus, the ferromagneticconductor may be chosen primarily for its ferromagnetic properties.

Confining the majority of the flow of electrical current to theelectrical conductor below the Curie temperature and/or the phasetransformation temperature range of the ferromagnetic conductor reducesvariations in the power factor. Because only a portion of the electricalcurrent flows through the ferromagnetic conductor below the Curietemperature and/or the phase transformation temperature range, thenon-linear ferromagnetic properties of the ferromagnetic conductor havelittle or no effect on the power factor of the temperature limitedheater, except at or near the Curie temperature and/or the phasetransformation temperature range. Even at or near the Curie temperatureand/or the phase transformation temperature range, the effect on thepower factor is reduced compared to temperature limited heaters in whichthe ferromagnetic conductor provides a majority of the resistive heatoutput below the Curie temperature and/or the phase transformationtemperature range. Thus, there is less or no need for externalcompensation (for example, variable capacitors or waveform modification)to adjust for changes in the inductive load of the temperature limitedheater to maintain a relatively high power factor.

In certain embodiments, the temperature limited heater, which confinesthe majority of the flow of electrical current to the electricalconductor below the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor, maintains the powerfactor above 0.85, above 0.9, or above 0.95 during use of the heater.Any reduction in the power factor occurs only in sections of thetemperature limited heater at temperatures near the Curie temperatureand/or the phase transformation temperature range. Most sections of thetemperature limited heater are typically not at or near the Curietemperature and/or the phase transformation temperature range duringuse. These sections have a high power factor that approaches 1.0. Thepower factor for the entire temperature limited heater is maintainedabove 0.85, above 0.9, or above 0.95 during use of the heater even ifsome sections of the heater have power factors below 0.85.

Maintaining high power factors allows for less expensive power suppliesand/or control devices such as solid state power supplies or SCRs(silicon controlled rectifiers). These devices may fail to operateproperly if the power factor varies by too large an amount because ofinductive loads. With the power factors maintained at high values;however, these devices may be used to provide power to the temperaturelimited heater. Solid state power supplies have the advantage ofallowing fine tuning and controlled adjustment of the power supplied tothe temperature limited heater.

In some embodiments, transformers are used to provide power to thetemperature limited heater. Multiple voltage taps may be made into thetransformer to provide power to the temperature limited heater. Multiplevoltage taps allows the current supplied to switch back and forthbetween the multiple voltages. This maintains the current within a rangebound by the multiple voltage taps.

The highly electrically conductive member, or inner conductor, increasesthe turndown ratio of the temperature limited heater. In certainembodiments, thickness of the highly electrically conductive member isincreased to increase the turndown ratio of the temperature limitedheater. In some embodiments, the thickness of the electrical conductoris reduced to increase the turndown ratio of the temperature limitedheater. In certain embodiments, the turndown ratio of the temperaturelimited heater is between 1.1 and 10, between 2 and 8, or between 3 and6 (for example, the turndown ratio is at least 1.1, at least 2, or atleast 3).

FIG. 37 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. Core 508 is an inner conductor of thetemperature limited heater. In certain embodiments, core 508 is a highlyelectrically conductive material such as copper or aluminum. In someembodiments, core 508 is a copper alloy that provides mechanicalstrength and good electrically conductivity such as a dispersionstrengthened copper. In one embodiment, core 508 is Glidcop® (SCM MetalProducts, Inc., Research Triangle Park, N.C., U.S.A.). Ferromagneticconductor 512 is a thin layer of ferromagnetic material betweenelectrical conductor 538 and core 508. In certain embodiments,electrical conductor 538 is also support member 514. In certainembodiments, ferromagnetic conductor 512 is iron or an iron alloy. Insome embodiments, ferromagnetic conductor 512 includes ferromagneticmaterial with a high relative magnetic permeability. For example,ferromagnetic conductor 512 may be purified iron such as Armco ingotiron (AK Steel Ltd., United Kingdom). Iron with some impuritiestypically has a relative magnetic permeability on the order of 400.Purifying the iron by annealing the iron in hydrogen gas (H₂) at 1450°C. increases the relative magnetic permeability of the iron. Increasingthe relative magnetic permeability of ferromagnetic conductor 512 allowsthe thickness of the ferromagnetic conductor to be reduced. For example,the thickness of unpurified iron may be approximately 4.5 mm while thethickness of the purified iron is approximately 0.76 mm.

In certain embodiments, electrical conductor 538 provides support forferromagnetic conductor 512 and the temperature limited heater.Electrical conductor 538 may be made of a material that provides goodmechanical strength at temperatures near or above the Curie temperatureand/or the phase transformation temperature range of ferromagneticconductor 512. In certain embodiments, electrical conductor 538 is acorrosion resistant member. Electrical conductor 538 (support member514) may provide support for ferromagnetic conductor 512 and corrosionresistance. Electrical conductor 538 is made from a material thatprovides desired electrically resistive heat output at temperatures upto and/or above the Curie temperature and/or the phase transformationtemperature range of ferromagnetic conductor 512.

In an embodiment, electrical conductor 538 is 347H stainless steel. Insome embodiments, electrical conductor 538 is another electricallyconductive, good mechanical strength, corrosion resistant material. Forexample, electrical conductor 538 may be 304H, 316H, 347HH, NF709,Incoloy® 800H alloy (Inco Alloys International, Huntington, West Va.,U.S.A.), Haynes® HR120® alloy, or Inconel® 617 alloy.

In some embodiments, electrical conductor 538 (support member 514)includes different alloys in different portions of the temperaturelimited heater. For example, a lower portion of electrical conductor 538(support member 514) is 347H stainless steel and an upper portion of theelectrical conductor (support member) is NF709. In certain embodiments,different alloys are used in different portions of the electricalconductor (support member) to increase the mechanical strength of theelectrical conductor (support member) while maintaining desired heatingproperties for the temperature limited heater.

In some embodiments, ferromagnetic conductor 512 includes differentferromagnetic conductors in different portions of the temperaturelimited heater. Different ferromagnetic conductors may be used indifferent portions of the temperature limited heater to vary the Curietemperature and/or the phase transformation temperature range and, thus,the maximum operating temperature in the different portions. In someembodiments, the Curie temperature and/or the phase transformationtemperature range in an upper portion of the temperature limited heateris lower than the Curie temperature and/or the phase transformationtemperature range in a lower portion of the heater. The lower Curietemperature and/or the phase transformation temperature range in theupper portion increases the creep-rupture strength lifetime in the upperportion of the heater.

In the embodiment depicted in FIG. 37, ferromagnetic conductor 512,electrical conductor 538, and core 508 are dimensioned so that the skindepth of the ferromagnetic conductor limits the penetration depth of themajority of the flow of electrical current to the support member whenthe temperature is below the Curie temperature and/or the phasetransformation temperature range of the ferromagnetic conductor. Thus,electrical conductor 538 provides a majority of the electricallyresistive heat output of the temperature limited heater at temperaturesup to a temperature at or near the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 512. Incertain embodiments, the temperature limited heater depicted in FIG. 37is smaller (for example, an outside diameter of 3 cm, 2.9 cm, 2.5 cm, orless) than other temperature limited heaters that do not use electricalconductor 538 to provide the majority of electrically resistive heatoutput. The temperature limited heater depicted in FIG. 37 may besmaller because ferromagnetic conductor 512 is thin as compared to thesize of the ferromagnetic conductor needed for a temperature limitedheater in which the majority of the resistive heat output is provided bythe ferromagnetic conductor.

In some embodiments, the support member and the corrosion resistantmember are different members in the temperature limited heater. FIGS. 38and 39 depict embodiments of temperature limited heaters in which thejacket provides a majority of the heat output below the Curietemperature and/or the phase transformation temperature range of theferromagnetic conductor. In these embodiments, electrical conductor 538is jacket 506. Electrical conductor 538, ferromagnetic conductor 512,support member 514, and core 508 (in FIG. 38) or inner conductor 490 (inFIG. 39) are dimensioned so that the skin depth of the ferromagneticconductor limits the penetration depth of the majority of the flow ofelectrical current to the thickness of the jacket. In certainembodiments, electrical conductor 538 is a material that is corrosionresistant and provides electrically resistive heat output below theCurie temperature and/or the phase transformation temperature range offerromagnetic conductor 512. For example, electrical conductor 538 is825 stainless steel or 347H stainless steel. In some embodiments,electrical conductor 538 has a small thickness (for example, on theorder of 0.5 mm).

In FIG. 38, core 508 is highly electrically conductive material such ascopper or aluminum. Support member 514 is 347H stainless steel oranother material with good mechanical strength at or near the Curietemperature and/or the phase transformation temperature range offerromagnetic conductor 512.

In FIG. 39, support member 514 is the core of the temperature limitedheater and is 347H stainless steel or another material with goodmechanical strength at or near the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 512. Innerconductor 490 is highly electrically conductive material such as copperor aluminum.

In certain embodiments, the materials and design of the temperaturelimited heater are chosen to allow use of the heater at hightemperatures (for example, above 850° C.). FIG. 40 depicts a hightemperature embodiment of the temperature limited heater. The heaterdepicted in FIG. 40 operates as a conductor-in-conduit heater with themajority of heat being generated in conduit 518. Theconductor-in-conduit heater may provide a higher heat output because themajority of heat is generated in conduit 518 rather than conductor 516.Having the heat generated in conduit 518 reduces heat losses associatedwith transferring heat between the conduit and conductor 516.

Core 508 and conductive layer 510 are copper. In some embodiments, core508 and conductive layer 510 are nickel if the operating temperatures isto be near or above the melting point of copper. Support members 514 areelectrically conductive materials with good mechanical strength at hightemperatures. Materials for support members 514 that withstand at leasta maximum temperature of about 870° C. may be, but are not limited to,MO-RE® alloys (Duraloy Technologies, Inc. (Scottdale, Pa., U.S.A.)),CF8C+(Metaltek Intl. (Waukesha, Wis., U.S.A.)), or Inconel® 617 alloy.Materials for support members 514 that withstand at least a maximumtemperature of about 980° C. include, but are not limited to, Incoloy®Alloy MA 956. Support member 514 in conduit 518 provides mechanicalsupport for the conduit. Support member 514 in conductor 516 providesmechanical support for core 508.

Electrical conductor 538 is a thin corrosion resistant material. Incertain embodiments, electrical conductor 538 is 347H, 617, 625, or 800Hstainless steel. Ferromagnetic conductor 512 is a high Curie temperatureferromagnetic material such as iron-cobalt alloy (for example, a 15% byweight cobalt, iron-cobalt alloy).

In certain embodiments, electrical conductor 538 provides the majorityof heat output of the temperature limited heater at temperatures up to atemperature at or near the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 512.Conductive layer 510 increases the turndown ratio of the temperaturelimited heater.

For long vertical temperature limited heaters (for example, heaters atleast 300 m, at least 500 m, or at least 1 km in length), the hangingstress becomes important in the selection of materials for thetemperature limited heater. Without the proper selection of material,the support member may not have sufficient mechanical strength (forexample, creep-rupture strength) to support the weight of thetemperature limited heater at the operating temperatures of the heater.FIG. 41 depicts hanging stress (ksi (kilopounds per square inch)) versusoutside diameter (in.) for the temperature limited heater shown in FIG.37 with 347H as the support member. The hanging stress was assessed withthe support member outside a 0.5″ copper core and a 0.75″ outsidediameter carbon steel ferromagnetic conductor. This assessment assumesthe support member bears the entire load of the heater and that theheater length is 1000 ft. (about 305 m). As shown in FIG. 41, increasingthe thickness of the support member decreases the hanging stress on thesupport member. Decreasing the hanging stress on the support memberallows the temperature limited heater to operate at higher temperatures.

In certain embodiments, materials for the support member are varied toincrease the maximum allowable hanging stress at operating temperaturesof the temperature limited heater and, thus, increase the maximumoperating temperature of the temperature limited heater. Altering thematerials of the support member affects the heat output of thetemperature limited heater below the Curie temperature and/or the phasetransformation temperature range because changing the materials changesthe resistance versus temperature profile of the support member. Incertain embodiments, the support member is made of more than onematerial along the length of the heater so that the temperature limitedheater maintains desired operating properties (for example, resistanceversus temperature profile below the Curie temperature and/or the phasetransformation temperature range) as much as possible while providingsufficient mechanical properties to support the heater.

FIG. 42 depicts hanging stress (ksi) versus temperature (° F.) forseveral materials and varying outside diameters for the temperaturelimited heaters. Curve 540 is for 347H stainless steel. Curve 542 is forIncoloy® alloy 800H. Curve 544 is for Haynes® HR120® alloy. Curve 546 isfor NF709. Each of the curves includes four points that representvarious outside diameters of the support member. The point with thehighest stress for each curve corresponds to outside diameter of 1.05″.The point with the second highest stress for each curve corresponds tooutside diameter of 1.15″. The point with the second lowest stress foreach curve corresponds to outside diameter of 1.25″. The point with thelowest stress for each curve corresponds to outside diameter of 1.315″.As shown in FIG. 42, increasing the strength and/or outside diameter ofthe material and the support member increases the maximum operatingtemperature of the temperature limited heater.

FIGS. 43, 44, 45, and 46 depict examples of embodiments for temperaturelimited heaters able to provide desired heat output and mechanicalstrength for operating temperatures up to about 770° C. for 30,000 hrs.creep-rupture lifetime. The depicted temperature limited heaters havelengths of 1000 ft, copper cores of 0.5″ diameter, and ironferromagnetic conductors with outside diameters of 0.765″. In FIG. 43,the support member in heater portion 548 is 347H stainless steel. Thesupport member in heater portion 550 is Incoloy® alloy 800H. Portion 548has a length of 750 ft. and portion 550 has a length of 250 ft. Theoutside diameter of the support member is 1.315″. In FIG. 44, thesupport member in heater portion 548 is 347H stainless steel. Thesupport member in heater portion 550 is Incoloy® alloy 800H. The supportmember in heater portion 552 is Haynes® HR120® alloy. Portion 548 has alength of 650 ft., portion 550 has a length of 300 ft., and portion 552has a length of 50 ft. The outside diameter of the support member is1.15″. In FIG. 45, the support member in heater portion 548 is 347Hstainless steel. The support member in heater portion 550 is Incoloy®alloy 800H. The support member in heater portion 552 is Haynes® HR120®alloy. Portion 548 has a length of 550 ft., portion 550 has a length of250 ft., and portion 552 has a length of 200 ft. The outside diameter ofthe support member is 1.05″.

In some embodiments, a transition section is used between sections ofthe heater. For example, if one or more portions of the heater havevarying Curie temperatures and/or phase transformation temperatureranges, a transition section may be used between portions to providestrength that compensates for the differences in temperatures in theportions. FIG. 46 depicts another example of an embodiment of atemperature limited heater able to provide desired heat output andmechanical strength. The support member in heater portion 548 is 347Hstainless steel. The support member in heater portion 550 is NF709. Thesupport member in heater portion 552 is 347H. Portion 548 has a lengthof 550 ft. and a Curie temperature of 843° C., portion 550 has a lengthof 250 ft. and a Curie temperature of 843° C., and portion 552 has alength of 180 ft. and a Curie temperature of 770° C. Transition section554 has a length of 20 ft., a Curie temperature of 770° C., and thesupport member is NF709.

The materials of the support member along the length of the temperaturelimited heater may be varied to achieve a variety of desired operatingproperties. The choice of the materials of the temperature limitedheater is adjusted depending on a desired use of the temperature limitedheater. TABLE 2 lists examples of materials that may be used for thesupport member. The table provides the hanging stresses (a) of thesupport members and the maximum operating temperatures of thetemperature limited heaters for several different outside diameters (OD)of the support member. The core diameter and the outside diameter of theiron ferromagnetic conductor in each case are 0.5″ and 0.765″,respectively.

TABLE 2 OD = 1.05″ OD = 1.15″ OD = 1.25″ OD = 1.315″ Material σ (ksi) T(° F.) σ (ksi) T (° F.) σ (ksi) T (° F.) σ (ksi) T (° F.) 347H stainless7.55 1310 6.33 1340 5.63 1360 5.31 1370 steel Incoloy ® alloy 7.55 13376.33 1378 5.63 1400 5.31 1420 800H Haynes ® HR120 ® 7.57 1450 6.36 14925.65 1520 5.34 1540 alloy HA230 7.91 1475 6.69 1510 5.99 1530 5.67 1540Haynes ® alloy 556 7.65 1458 6.43 1492 5.72 1512 5.41 1520 NF709 7.571440 6.36 1480 5.65 1502 5.34 1512

In certain embodiments, one or more portions of the temperature limitedheater have varying outside diameters and/or materials to providedesired properties for the heater. FIGS. 47 and 48 depict examples ofembodiments for temperature limited heaters that vary the diameterand/or materials of the support member along the length of the heatersto provide desired operating properties and sufficient mechanicalproperties (for example, creep-rupture strength properties) foroperating temperatures up to about 834° C. for 30,000 hrs., heaterlengths of 850 ft, a copper core diameter of 0.5″, and an iron-cobalt(6% by weight cobalt) ferromagnetic conductor outside diameter of 0.75″.In FIG. 47, portion 548 is 347H stainless steel with a length of 300 ftand an outside diameter of 1.15″. Portion 550 is NF709 with a length of400 ft and an outside diameter of 1.15″. Portion 552 is NF709 with alength of 150 ft and an outside diameter of 1.25″. In FIG. 48, portion548 is 347H stainless steel with a length of 300 ft and an outsidediameter of 1.15″. Portion 550 is 347H stainless steel with a length of100 ft and an outside diameter of 1.20″. Portion 552 is NF709 with alength of 350 ft and an outside diameter of 1.20″. Portion 556 is NF709with a length of 100 ft and an outside diameter of 1.25″.

In certain embodiments, one or more portions of the temperature limitedheater have varying dimensions and/or varying materials to providedifferent power outputs along the length of the heater. More or lesspower output may be provided by varying the selected temperature (forexample, the Curie temperature and/or the phase transformationtemperature range) of the temperature limited heater by using differentferromagnetic materials along its length and/or by varying theelectrical resistance of the heater by using different dimensions in theheat generating member along the length of the heater. Different poweroutputs along the length of the temperature limited heater may be neededto compensate for different thermal properties in the formation adjacentto the heater. For example, an oil shale formation may have differentwater-filled porosities, dawsonite compositions, and/or nahcolitecompositions at different depths in the formation. Portions of theformation with higher water-filled porosities, higher dawsonitecompositions, and/or higher nahcolite compositions may need more powerinput than portions with lower water-filled porosities, lower dawsonitecompositions, and/or lower nahcolite compositions to achieve a similarheating rate. Power output may be varied along the length of the heaterso that the portions of the formation with different properties (such aswater-filled porosities, dawsonite compositions, and/or nahcolitecompositions) are heated at approximately the same heating rate.

In certain embodiments, portions of the temperature limited heater havedifferent selected self-limiting temperatures (for example, Curietemperatures and/or phase transformation temperature ranges), materials,and/or dimensions to compensate for varying thermal properties of theformation along the length of the heater. For example, Curietemperatures, phase transformation temperature ranges, support membermaterials, and/or dimensions of the portions of the heaters depicted inFIGS. 43-48 may be varied to provide varying power outputs and/oroperating temperatures along the length of the heater.

As one example, in an embodiment of the temperature limited heaterdepicted in FIG. 43, portion 550 may be used to heat portions of theformation that, on average, have higher water-filled porosities,dawsonite compositions, and/or nahcolite compositions than portions ofthe formation heated by portion 548. Portion 550 may provide less poweroutput than portion 548 to compensate for the differing thermalproperties of the different portions of the formation so that the entireformation is heated at an approximately constant heating rate. Portion550 may require less power output because, for example, portion 550 isused to heat portions of the formation with low water-filled porositiesand/or little or no dawsonite. In one embodiment, portion 550 has aCurie temperature of 770° C. (pure iron) and portion 548 has a Curietemperature of 843° C. (iron with added cobalt). Such an embodiment mayprovide more power output from portion 548 so that the temperature lagbetween the two portions is reduced. Adjusting the Curie temperature ofportions of the heater adjusts the selected temperature at which theheater self-limits. In some embodiments, the dimensions of portion 550are adjusted to further reduce the temperature lag so that the formationis heated at an approximately constant heating rate throughout theformation. Dimensions of the heater may be adjusted to adjust theheating rate of one or more portions of the heater. For example, thethickness of an outer conductor in portion 550 may be increased relativeto the ferromagnetic member and/or the core of the heater so that theportion has a higher electrical resistance and the portion provides ahigher power output below the Curie temperature of the portion.

Reducing the temperature lag between different portions of the formationmay reduce the overall time needed to bring the formation to a desiredtemperature. Reducing the time needed to bring the formation to thedesired temperature reduces heating costs and produces desirableproduction fluids more quickly.

Temperature limited heaters with varying Curie temperatures and/or phasetransformation temperature ranges may also have varying support membermaterials to provide mechanical strength for the heater (for example, tocompensate for hanging stress of the heater and/or provide sufficientcreep-rupture strength properties). For example, in the embodiment ofthe temperature limited heater depicted in FIG. 46, portions 548 and 550have a Curie temperature of 843° C. Portion 548 has a support membermade of 347H stainless steel. Portion 550 has a support member made ofNF709. Portion 552 has a Curie temperature of 770° C. and a supportmember made of 347H stainless steel. Transition section 554 has a Curietemperature of 770° C. and a support member made of NF709. Transitionsection 554 may be short in length compared to portions 548, 550, and552. Transition section 554 may be placed between portions 550 and 552to compensate for the temperature and material differences between theportions. For example, transition section 554 may be used to compensatefor differences in creep properties between portions 550 and 552.

Such a substantially vertical temperature limited heater may have lessexpensive, lower strength materials in portion 552 because of the lowerCurie temperature in this portion of the heater. For example, 347Hstainless steel may be used for the support member because of the lowermaximum operating temperature of portion 552 as compared to portion 550.Portion 550 may require more expensive, higher strength material becauseof the higher operating temperature of portion 550 due to the higherCurie temperature in this portion.

In some embodiments, a relatively thin conductive layer is used toprovide the majority of the electrically resistive heat output of thetemperature limited heater at temperatures up to a temperature at ornear the Curie temperature and/or the phase transformation temperaturerange of the ferromagnetic conductor. Such a temperature limited heatermay be used as the heating member in an insulated conductor heater. Theheating member of the insulated conductor heater may be located inside asheath with an insulation layer between the sheath and the heatingmember.

FIGS. 49A and 49B depict cross-sectional representations of anembodiment of the insulated conductor heater with the temperaturelimited heater as the heating member. Insulated conductor 558 includescore 508, ferromagnetic conductor 512, inner conductor 490, electricalinsulator 500, and jacket 506. Core 508 is a copper core. Ferromagneticconductor 512 is, for example, iron or an iron alloy.

Inner conductor 490 is a relatively thin conductive layer ofnon-ferromagnetic material with a higher electrical conductivity thanferromagnetic conductor 512. In certain embodiments, inner conductor 490is copper. Inner conductor 490 may be a copper alloy. Copper alloystypically have a flatter resistance versus temperature profile than purecopper. A flatter resistance versus temperature profile may provide lessvariation in the heat output as a function of temperature up to theCurie temperature and/or the phase transformation temperature range. Insome embodiments, inner conductor 490 is copper with 6% by weight nickel(for example, CuNi6 or LOHM™). In some embodiments, inner conductor 490is CuNi10Fe1Mn alloy. Below the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 512, themagnetic properties of the ferromagnetic conductor confine the majorityof the flow of electrical current to inner conductor 490. Thus, innerconductor 490 provides the majority of the resistive heat output ofinsulated conductor 558 below the Curie temperature and/or the phasetransformation temperature range.

In certain embodiments, inner conductor 490 is dimensioned, along withcore 508 and ferromagnetic conductor 512, so that the inner conductorprovides a desired amount of heat output and a desired turndown ratio.For example, inner conductor 490 may have a cross-sectional area that isaround 2 or 3 times less than the cross-sectional area of core 508.Typically, inner conductor 490 has to have a relatively smallcross-sectional area to provide a desired heat output if the innerconductor is copper or copper alloy. In an embodiment with copper innerconductor 490, core 508 has a diameter of 0.66 cm, ferromagneticconductor 512 has an outside diameter of 0.91 cm, inner conductor 490has an outside diameter of 1.03 cm, electrical insulator 500 has anoutside diameter of 1.53 cm, and jacket 506 has an outside diameter of1.79 cm. In an embodiment with a CuNi6 inner conductor 490, core 508 hasa diameter of 0.66 cm, ferromagnetic conductor 512 has an outsidediameter of 0.91 cm, inner conductor 490 has an outside diameter of 1.12cm, electrical insulator 500 has an outside diameter of 1.63 cm, andjacket 506 has an outside diameter of 1.88 cm. Such insulated conductorsare typically smaller and cheaper to manufacture than insulatedconductors that do not use the thin inner conductor to provide themajority of heat output below the Curie temperature and/or the phasetransformation temperature range.

Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicondioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. In certain embodiments, electrical insulator 500is a compacted powder of magnesium oxide. In some embodiments,electrical insulator 500 includes beads of silicon nitride.

In certain embodiments, a small layer of material is placed betweenelectrical insulator 500 and inner conductor 490 to inhibit copper frommigrating into the electrical insulator at higher temperatures. Forexample, the small layer of nickel (for example, about 0.5 mm of nickel)may be placed between electrical insulator 500 and inner conductor 490.

Jacket 506 is made of a corrosion resistant material such as, but notlimited to, 347 stainless steel, 347H stainless steel, 446 stainlesssteel, or 825 stainless steel. In some embodiments, jacket 506 providessome mechanical strength for insulated conductor 558 at or above theCurie temperature and/or the phase transformation temperature range offerromagnetic conductor 512. In certain embodiments, jacket 506 is notused to conduct electrical current.

In certain embodiments of temperature limited heaters, three temperaturelimited heaters are coupled together in a three-phase wye configuration.Coupling three temperature limited heaters together in the three-phasewye configuration lowers the current in each of the individualtemperature limited heaters because the current is split between thethree individual heaters. Lowering the current in each individualtemperature limited heater allows each heater to have a small diameter.The lower currents allow for higher relative magnetic permeabilities ineach of the individual temperature limited heaters and, thus, higherturndown ratios. In addition, there may be no return current needed foreach of the individual temperature limited heaters. Thus, the turndownratio remains higher for each of the individual temperature limitedheaters than if each temperature limited heater had its own returncurrent path.

In the three-phase wye configuration, individual temperature limitedheaters may be coupled together by shorting the sheaths, jackets, orcanisters of each of the individual temperature limited heaters to theelectrically conductive sections (the conductors providing heat) attheir terminating ends (for example, the ends of the heaters at thebottom of a heater wellbore). In some embodiments, the sheaths, jackets,canisters, and/or electrically conductive sections are coupled to asupport member that supports the temperature limited heaters in thewellbore.

FIG. 50A depicts an embodiment for installing and coupling heaters in awellbore. The embodiment in FIG. 50A depicts insulated conductor heatersbeing installed into the wellbore. Other types of heaters, such asconductor-in-conduit heaters, may also be installed in the wellboreusing the embodiment depicted. Also, in FIG. 50A, two insulatedconductors 558 are shown while a third insulated conductor is not seenfrom the view depicted. Typically, three insulated conductors 558 wouldbe coupled to support member 560, as shown in FIG. 50B. In anembodiment, support member 560 is a thick walled 347H pipe. In someembodiments, thermocouples or other temperature sensors are placedinside support member 560. The three insulated conductors may be coupledin a three-phase wye configuration.

In FIG. 50A, insulated conductors 558 are coiled on coiled tubing rigs562. As insulated conductors 558 are uncoiled from rigs 562, theinsulated conductors are coupled to support member 560. In certainembodiments, insulated conductors 558 are simultaneously uncoiled and/orsimultaneously coupled to support member 560. Insulated conductors 558may be coupled to support member 560 using metal (for example, 304stainless steel or Inconel® alloys) straps 564. In some embodiments,insulated conductors 558 are coupled to support member 560 using othertypes of fasteners such as buckles, wire holders, or snaps. Supportmember 560 along with insulated conductors 558 are installed intoopening 522. In some embodiments, insulated conductors 558 are coupledtogether without the use of a support member. For example, one or morestraps 564 may be used to couple insulated conductors 558 together.

Insulated conductors 558 may be electrically coupled to each other at alower end of the insulated conductors. In a three-phase wyeconfiguration, insulated conductors 558 operate without a current returnpath. In certain embodiments, insulated conductors 558 are electricallycoupled to each other in contactor section 566. In section 566, sheaths,jackets, canisters, and/or electrically conductive sections areelectrically coupled to each other and/or to support member 560 so thatinsulated conductors 558 are electrically coupled in the section.

In certain embodiments, the sheaths of insulated conductors 558 areshorted to the conductors of the insulated conductors. FIG. 50C depictsan embodiment of insulated conductor 558 with the sheath shorted to theconductors. Sheath 506 is electrically coupled to core 508,ferromagnetic conductor 512, and inner conductor 490 using termination568. Termination 568 may be a metal strip or a metal plate at the lowerend of insulated conductor 558. For example, termination 568 may be acopper plate coupled to sheath 506, core 508, ferromagnetic conductor512, and inner conductor 490 so that they are shorted together. In someembodiments, termination 568 is welded or brazed to sheath 506, core508, ferromagnetic conductor 512, and inner conductor 490.

The sheaths of individual insulated conductors 558 may be shortedtogether to electrically couple the conductors of the insulatedconductors, depicted in FIGS. 50A and 50B. In some embodiments, thesheaths may be shorted together because the sheaths are in physicalcontact with each other. For example, the sheaths may in physicalcontact if the sheaths are strapped together by straps 564. In someembodiments, the lower ends of the sheaths are physically coupled (forexample, welded) at the surface of opening 522 before insulatedconductors 558 are installed into the opening.

In certain embodiments, coupling multiple heaters (for example,insulated conductor, or mineral insulated conductor, heaters) to asingle power source, such as a transformer, is advantageous. Couplingmultiple heaters to a single transformer may result in using fewertransformers to power heaters used for a treatment area as compared tousing individual transformers for each heater. Using fewer transformersreduces surface congestion and allows easier access to the heaters andsurface components. Using fewer transformers reduces capital costsassociated with providing power to the treatment area. In someembodiments, at least 4, at least 5, at least 10, at least 25 heaters,at least 35 heaters, or at least 45 heaters are powered by a singletransformer. Additionally, powering multiple heaters (in differentheater wells) from the single transformer may reduce overburden lossesbecause of reduced voltage and/or phase differences between each of theheater wells powered by the single transformer. Powering multipleheaters from the single transformer may inhibit current imbalancesbetween the heaters because the heaters are coupled to the singletransformer.

In order to provide power to multiple heaters using the singletransformer, the transformer may have to provide power at highervoltages to carry the current to each of the heaters effectively. Incertain embodiments, the heaters are floating (ungrounded) heaters inthe formation. Floating the heaters allows the heaters to operate athigher voltages. In some embodiments, the transformer provides poweroutput of at least about 3 kV, at least about 4 kV, at least about 5 kV,or at least about 6 kV.

FIG. 51 depicts a top view representation of heater 716 with threeinsulated conductors 558 in conduit 536. Heater 716 includes threeinsulated conductors 558 in conduit 536. Heater 716 may be located in aheater well in the subsurface formation. Conduit 536 may be a sheath,jacket, or other enclosure around insulated conductors 558. Eachinsulated conductor 558 includes core 508, electrical insulator 500, andjacket 506. Insulated conductors 558 may be mineral insulated conductorswith core 508 being a copper alloy (for example, a copper-nickel alloysuch as Alloy 180), electrical insulator 500 being magnesium oxide, andjacket 506 being Incoloy® 825, copper, or stainless steel (for example347H stainless steel). In some embodiments, jacket 506 includes non-workhardenable metals so that the jacket is annealable.

In some embodiments, core 508 and/or jacket 506 include ferromagneticmaterials. In some embodiments, one or more insulated conductors 558 aretemperature limited heaters. In certain embodiments, the overburdenportion of insulated conductors 558 include high electrical conductivitymaterials in core 508 (for example, pure copper or copper alloys such ascopper with 3% silicon at a weld joint) so that the overburden portionsof the insulated conductors provide little or no heat output. In certainembodiments, conduit 536 includes non-corrosive materials and/or highstrength materials such as stainless steel. In one embodiment, conduit536 is 347H stainless steel.

Insulated conductors 558 may be coupled to the single transformer in athree-phase configuration (for example, a three-phase wyeconfiguration). Each insulated conductor 558 may be coupled to one phaseof the single transformer. In certain embodiments, the singletransformer is also coupled to a plurality of identical heaters 716 inother heater wells in the formation (for example, the single transformermay couple to 40 heaters or more in the formation). In some embodiments,the single transformer couples to at least 4, at least 5, at least 10,at least 15, or at least 25 additional heaters in the formation.

FIG. 52 depicts an embodiment of three-phase wye transformer 728 coupledto a plurality of heaters 716. For simplicity in the drawing, only fourheaters 716 are shown in FIG. 52. It is to be understood that severalmore heaters may be coupled to the transformer 728. As shown in FIG. 52,each leg (each insulated conductor) of each heater is coupled to onephase of transformer 728 and current returned to the neutral or groundof the transformer (for example, returned through conductor 2024depicted in FIGS. 51 and 53).

Electrical insulator 500′ may be located inside conduit 536 toelectrically insulate insulated conductors 558 from the conduit. Incertain embodiments, electrical insulator 500′ is magnesium oxide (forexample, compacted magnesium oxide). In some embodiments, electricalinsulator 500′ is silicon nitride (for example, silicon nitride blocks).Electrical insulator 500′ electrically insulates insulated conductors558 from conduit 536 so that at high operating voltages (for example, 3kV or higher), there is no arcing between the conductors and theconduit. In some embodiments, electrical insulator 500′ inside conduit536 has at least the thickness of electrical insulators 500 in insulatedconductors 558. The increased thickness of insulation in heater 716(from electrical insulators 500 and/or electrical insulator 500′)inhibits and may prevent current leakage into the formation from theheater. In some embodiments, electrical insulator 500′ spatially locatesinsulated conductors 558 inside conduit 536.

Return conductor 2024 may be electrically coupled to the ends ofinsulated conductors 558 (as shown in FIG. 53) and return current fromthe ends of the insulated conductors to the transformer on the surfaceof the formation. Return conductor 2024 may include high electricalconductivity materials such as pure copper, nickel, copper alloys, orcombinations thereof so that the return conductor provides little or noheat output. In some embodiments, return conductor 2024 is a tubular(for example, a stainless steel tubular) that allows an optical fiber tobe placed inside the tubular and used for temperature measurement. Insome embodiments, return conductor 2024 is a small insulated conductor(for example, small mineral insulated conductor). Return conductor 2024may be coupled to the neutral or ground leg of the transformer in athree-phase wye configuration. Thus, insulated conductors 558 areelectrically isolated from conduit 536 and the formation. Using returnconductor 2024 to return current to the surface may make coupling theheater to a wellhead easier. In some embodiments, current is returnedusing one or more of jackets 506, depicted in FIG. 51. One or morejackets 506 may be coupled to cores 508 at the end of the heaters andreturn current to the neutral of the three-phase wye transformer.

FIG. 53 depicts a side view representation of the end section of threeinsulated conductors 558 in conduit 536. The end section is the sectionof the heaters the furthest away from (distal from) the surface of theformation. The end section includes contactor section 566 coupled toconduit 536. In some embodiments, contactor section 566 is welded orbrazed to conduit 536. Termination 568 is located in contactor section566. Termination 568 is electrically coupled to insulated conductors 558and return conductor 2024. Termination 568 electrically couples thecores of insulated conductors 558 to the return conductor 2024 at theends of the heaters.

In certain embodiments, heater 716, depicted in FIGS. 51 and 53,includes an overburden section using copper as the core of the insulatedconductors. The copper in the overburden section may be the samediameter as the cores used in the heating section of the heater. Thecopper in the overburden section may have a larger diameter than thecores in the heating section of the heater. Increasing the size of thecopper in the overburden section may decrease losses in the overburdensection of the heater.

Heaters that include three insulated conductors 558 in conduit 536, asdepicted in FIGS. 51 and 53, may be made in a multiple step process. Insome embodiments, the multiple step process is performed at the site ofthe formation or treatment area. In some embodiments, the multiple stepprocess is performed at a remote manufacturing site away from theformation. The finished heater is then transported to the treatmentarea.

Insulated conductors 558 may be pre-assembled prior to the bundlingeither on site or at a remote location. Insulated conductors 558 andreturn conductor 2024 may be positioned on spools. A machine may drawinsulated conductors 558 and return conductor 2024 from the spools at aselected rate. Preformed blocks of insulation material may be positionedaround return conductor 2024 and insulated conductors 558. In anembodiment, two blocks are positioned around return conductor 2024 andthree blocks are positioned around insulated conductors 558 to formelectrical insulator 500′. The insulated conductors and return conductormay be drawn or pushed into a plate of conduit material that has beenrolled into a tubular shape. The edges of the plate may be pressedtogether and welded (for example, by laser welding). After formingconduit 536 around electrical insulator 500′, the bundle of insulatedconductors 558, and return conductor 2024, the conduit may be compactedagainst the electrical insulator 2024 so that all of the components ofthe heater are pressed together into a compact and tightly fitting form.During the compaction, the electrical insulator may flow and fill anygaps inside the heater.

In some embodiments, heater 716 (which includes conduit 536 aroundelectrical insulator 500′ and the bundle of insulated conductors 558 andreturn conductor 2024) is inserted into a coiled tubing tubular that isplaced in a wellbore in the formation. The coiled tubing tubular may beleft in place in the formation (left in during heating of the formation)or removed from the formation after installation of the heater. Thecoiled tubing tubular may allow for easier installation of heater 716into the wellbore.

In some embodiments, one or more components of heater 716 are varied(for example, removed, moved, or replaced) while the operation of theheater remains substantially identical. FIG. 54 depicts one alternativeembodiment of heater 716 with three insulated cores 508 in conduit 536.In this embodiment, electrical insulator 500′ surrounds cores 508 andreturn conductor 2024 in conduit 536. Cores 508 are located in conduit536 without electrical insulator 500 and jacket 506 surrounding thecores. Cores 508 are coupled to the single transformer in a three-phasewye configuration with each core 508 coupled to one phase of thetransformer. Return conductor 2024 is electrically coupled to the endsof cores 508 and returns current from the ends of the cores to thetransformer on the surface of the formation.

FIG. 55 depicts another alternative embodiment of heater 716 with threeinsulated conductors 558 and insulated return conductor in conduit 536.In this embodiment, return conductor 2024 is an insulated conductor withcore 508, electrical insulator 500, and jacket 506. Return conductor2024 and insulated conductors 558 are located in conduit 536 aresurrounded by electrical insulator 500 and conduit 536. Return conductor2024 and insulated conductors 558 may be the same size or differentsizes. Return conductor 2024 and insulated conductors 558 operatesubstantially the same as in the embodiment depicted in FIGS. 51 and 53.

FIG. 56 depicts an embodiment of insulated conductor 558 in conduit 518with molten metal. Insulated conductor 558 and conduit 518 may be placedin an opening in a subsurface formation. Insulated conductor 558 andconduit 518 may have any orientation in a subsurface formation (forexample, the insulated conductor and conduit may be substantiallyvertical or substantially horizontally oriented in the formation).Insulated conductor 558 includes core 508, electrical insulator 500, andjacket 506. In some embodiments, core 508 is a copper core. In someembodiments, core 508 includes other electrical conductors or alloys(for example, copper alloys). In some embodiments, core 508 includes aferromagnetic conductor so that insulated conductor 558 operates as atemperature limited heater.

Electrical insulator 500 may be magnesium oxide, aluminum oxide, silicondioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. In certain embodiments, electrical insulator 500is a compacted powder of magnesium oxide. In some embodiments,electrical insulator 500 includes beads of silicon nitride. In certainembodiments, a small layer of material is placed between electricalinsulator 500 and core 508 to inhibit copper from migrating into theelectrical insulator at higher temperatures. For example, the smalllayer of nickel (for example, about 0.5 mm of nickel) may be placedbetween electrical insulator 500 and core 508.

Jacket 506 is made of a corrosion resistant material such as, but notlimited to, 347 stainless steel, 347H stainless steel, 446 stainlesssteel, or 825 stainless steel. In some embodiments, jacket 506 is notused to conduct electrical current.

In an embodiment, core 508 has a diameter of about 1 cm, electricalinsulator 500 has an outside diameter of about 1.6 cm, and jacket 506has an outside diameter of about 1.8 cm.

In certain embodiments, molten metal 2026 is placed inside conduit 518in the space outside of insulated conductor 558. In certain embodiments,molten metal 2026 is placed in as balls or pellets of metal. The metalballs or pellets may be made of metal that melts below operatingtemperatures of insulated conductor 558 but above ambient subsurfaceformation temperatures. The metal balls or pellets may be placed inconduit 518 after insulated conductor 558 is placed in the conduit. Incertain embodiments, molten metal 2026 is placed in as a molten liquid.The molten liquid may be placed in conduit 518 before or after insulatedconductor 558 is placed in the conduit (for example, the molten liquidmay be poured into the conduit before or after the insulated conductoris placed in the conduit). Additionally, the molten liquid, or the metalballs or pellets, may be placed in conduit 518 before or after insulatedconductor 558 is energized (turned on).

Molten metal 2026 may remain a molten liquid at operating temperaturesof insulated conductor 558. In some embodiments, molten metal 2026 meltsat temperatures above about 100° C., above about 200° C., or above about300° C. Molten metal 2026 may remain a molten liquid at temperatures upto about 1400° C., about 1500° C., or about 1600° C. In certainembodiments, molten metal 2026 is a good thermal conductor at or nearthe operating temperatures of insulated conductor 558. Molten metal 2026may include metals such as tin, zinc, an alloy such as a 60% by weighttin, 40% by weight zinc alloy; bismuth; cadmium, aluminum; lead;arsenic; and/or combinations thereof. In one embodiment, molten metal2026 is tin. Molten metal 2026 may have a high Grashof number. Moltenmetals with high Grashof numbers will provide good convection currentsin conduit 518.

Molten metal 2026 fills the space between conduit 518 and insulatedconductor 558. Molten metal 2026 may increase heat transfer betweenconduit 518 and insulated conductor 558 by heat conduction through themolten metal and/or heat convection from movement of the molten metal inthe conduit. The temperature differential between conduit 518 andinsulated conductor 558 may create convection currents (heat generatedmovement) in the conduit. Convection of molten metal 2026 may inhibithot spots along conduit 518 and insulated conductor 558. Using moltenmetal 2026 allows insulated conductor 558 to be a smaller diameterinsulated conductor, which may be easier and/or cheaper to manufacture.

In some embodiments, molten metal 2026 returns electrical current to thesurface from insulated conductor 558 (the molten metal acts as thereturn or ground conductor for the insulated conductor). Molten metal2026 may provide a large current path with low resistance so that a longheater (long insulated conductor 558) is useable in conduit 518. Moltenmetal 2026 may also inhibit ferromagnetic effects in conduit 518, whichallows longer heaters with lower voltages. The long heater may operateat low voltages for the length of the heater due to the presence ofmolten metal 2026.

In certain embodiments, insulated conductor 558 is buoyant in the moltenmetal. The buoyancy of insulated conductor 558 reduces creep associatedproblems in long, substantially vertical heaters. A bottom weight or tiedown may be coupled to the bottom of insulated conductor 558 to inhibitthe insulated conductor from floating in the molten metal.

Conduit 518 may be a carbon steel or stainless steel canister. In anembodiment, conduit 518 is a canister of 410 stainless steel with anoutside diameter of about 6 cm. Conduit 518 may have thin walls asmolten metal 2026 may provide internal pressure that inhibitsdeformation or crushing of the conduit due to external stresses.

FIG. 57 depicts an embodiment of substantially horizontal insulatedconductor 558 in conduit 518 with molten metal 2026. Molten metal 2026may provide a head in conduit 518 due to the pressure of the moltenmetal. This pressure head may keep molten metal 2026 in conduit 518. Thepressure head may also provide internal pressure that inhibitsdeformation or collapse of the conduit due to external stresses.

In some embodiments, a long temperature limited heater (for example, atemperature limited heater in which the support member provides amajority of the heat output below the Curie temperature and/or the phasetransformation temperature range of the ferromagnetic conductor) isformed from several sections of heater. The sections of heater may becoupled using a welding process. FIG. 58 depicts an embodiment forcoupling together sections of a long temperature limited heater. Ends offerromagnetic conductors 512 and ends of electrical conductors 538(support members 514) are beveled to facilitate coupling the sections ofthe heater. Core 508 has recesses to allow core coupling material 570 tobe placed inside the abutted ends of the heater. Core coupling material570 may be a pin or dowel that fits tightly in the recesses of cores508. Core coupling material 570 may be made out of the same material ascores 508 or a material suitable for coupling the cores together. Corecoupling material 570 allows the heaters to be coupled together withoutwelding cores 508 together. Cores 508 are coupled together as a “pin” or“box” joint.

Beveled ends of ferromagnetic conductors 512 and electrical conductors538 may be coupled together with coupling material 572. In certainembodiments, ends of ferromagnetic conductors 512 and electricalconductors 538 are welded (for example, orbital welded) together.Coupling material 572 may be 625 stainless steel or any other suitablenon-ferromagnetic material for welding together ferromagnetic conductors512 and/or electrical conductors 538. Using beveled ends when couplingtogether sections of the heater may produce a reliable and durablecoupling between the sections of the heater.

During heating with the temperature limited heater, core couplingmaterial 570 may expand more radially than ferromagnetic conductors 512,electrical conductors 538, and/or coupling material 572. The greaterexpansion of core coupling material 570 maintains good electricalcontact with the core coupling material. At the coupling junction of theheater, electricity flows through core coupling material 570 rather thancoupling material 572. This flow of electricity inhibits heat generationat the coupling junction so that the junction remains at lowertemperatures than other portions of the heater during application ofelectrical current to the heater. The corrosion resistance and strengthof the coupling junction is increased by maintaining the junction atlower temperatures.

In certain embodiments, the junction may be enclosed in a shield duringorbital welding to enhance and/or ensure reliability of the weld. If thejunction is not enclosed, disturbance of the inert gas caused by wind,humidity or other conditions may cause oxidation and/or porosity of theweld. Without a shield, a first portion of the weld was formed andallowed to cool. A grinder would be used to remove the oxide layer. Theprocess would be repeated until the weld was complete. Enclosing thejunction in the shield with an inert gas allows the weld to be formedwith no oxidation, thus allowing the weld to be formed in one pass withno need for grinding. Enclosing the junction increases the safety offorming the weld because the arc of the orbital welder is enclosed inthe shield during welding. Enclosing the junction in the shield mayreduce the time needed to form the weld. Without a shield, producingeach weld may take 30 minutes or more. With the shield, each weld maytake 10 minutes or less.

FIG. 59 depicts an embodiment of a shield for orbital welding sectionsof a long temperature limited heater. Orbital welding may also be usedto form canisters for freeze wells from sections of pipe. Shield 574 mayinclude upper plate 576, lower plate 578, inserts 580, wall 582, hingeddoor 584, first clamp member 586, and second clamp member 588. Wall 582may include one or more inert gas inlets. Wall 582, upper plate 576,and/or lower plate 578 may include one or more openings for monitoringequipment or gas purging. Shield 574 is configured to work with anorbital welder, such as AMI Power Supply (Model 227) and AMI OrbitalWeld Head (Model 97-2375) available from Arc Machines, Inc. (Pacoima,Calif., U.S.A.). Inserts 580 may be withdrawn from upper plate 576 andlower plate 578. The orbital weld head may be positioned in shield 574.Shield 574 may be placed around a lower conductor of the conductors thatare to be welded together. When shield is positioned so that the end ofthe lower conductor is at a desired position in the middle of theshield, first clamp member may be fastened to second clamp member tosecure shield 574 to the lower conductor. The upper conductor may bepositioned in shield 574. Inserts 580 may be placed in upper plate 576and lower plate 578.

Hinged door 584 may be closed. When hinged door 584 is closed, shield574 forms a substantially airtight seal around the portions to be weldedtogether. The orbital welder may be located inside the shield. Theorbital welder may weld the lower conductor to the upper conductor. Incertain embodiments, an inert gas (such as argon or krypton) is providedthrough openings (for example, gas feedthroughs) in wall 582. The inertgas may be provided so that the interior of shield 574 is substantiallyor completely flushed with the inert gas and any oxidizing fluid (forexample, oxygen) is removed from inside the shield. A gas exit (forexample, a gas outlet or gas exit feedthrough) may allow gas to beflushed through shield 574. Having the inert gas inside shield 574during the welding process and removing oxidizing fluids (such asoxygen) from inside the shield, inhibits oxidization from occurringduring the welding process. Inhibiting oxidation during the weldingprocess inhibits the formation of oxide layers on the metals beingwelded and provides a more reliable welding process, a faster weldingprocess, and a more reliable weld junction.

In certain embodiments, a positive pressure of inert gas is maintainedinside shield 574 during the welding process. The positive pressure ofinert gas inhibits outside gases (for example, oxygen or other oxidizinggases) from entering the shield, even if the shield has one or moreleaks. In some embodiments, a vacuum may be pulled on shield 574 beforeproviding the inert gas into the shield and/or before welding theportions together. Pulling a vacuum on the shield may removecontaminants such as particulates from inside the shield.

Progress of the welding operation may be monitored through viewingwindows 590. When the weld is complete, shield 574 may be supported andfirst clamp member 586 may be unfastened from second clamp member 588.One or both inserts 580 may be removed or partially removed from lowerplate 578 and upper plate 576 to facilitate lowering of the conductor.The conductor may be lowered in the wellbore until the end of theconductor is located at a desired position in shield 574. Shield 574 maybe secured to the conductor with first clamp member 586 and second clampmember 588. Another conductor may be positioned in the shield. Inserts580 may be positioned in upper and lower plates 576, 578; hinged door isclosed 584; and the orbital welder is used to weld the conductorstogether. The process may be repeated until a desired length ofconductor is formed.

The shield may be used to weld joints of pipe over an opening in thehydrocarbon containing formation. Hydrocarbon vapors from the formationmay create an explosive atmosphere in the shield even though the inertgas supplied to the shield inhibits the formation of dangerousconcentrations of hydrocarbons in the shield. A control circuit may becoupled to a power supply for the orbital welder to stop power to theorbital welder to shut off the arc forming the weld if the hydrocarbonlevel in the shield rises above a selected concentration. FIG. 60depicts a schematic representation of an embodiment of a shut offcircuit for orbital welding machine 600. An inert gas, such as argon,may enter shield 574 through inlet 602. Gas may exit shield 574 throughpurge 604. Power supply 606 supplies electricity to orbital weldingmachine 600 through lines 608, 610. Switch 612 may be located in line608 to orbital welding machine 600. Switch 612 may be electricallycoupled to hydrocarbon monitor 614. Hydrocarbon monitor 614 may detectthe hydrocarbon concentration in shield 574. If the hydrocarbonconcentration in shield becomes too high, for example, over 25% of alower explosion limit concentration, hydrocarbon monitor 614 may openswitch 612. When switch 612 is open, power to orbital welder 600 isinterrupted and the arc formed by the orbital welder ends.

In some embodiments, the temperature limited heater is used to achievelower temperature heating (for example, for heating fluids in aproduction well, heating a surface pipeline, or reducing the viscosityof fluids in a wellbore or near wellbore region). Varying theferromagnetic materials of the temperature limited heater allows forlower temperature heating. In some embodiments, the ferromagneticconductor is made of material with a lower Curie temperature than thatof 446 stainless steel. For example, the ferromagnetic conductor may bean alloy of iron and nickel. The alloy may have between 30% by weightand 42% by weight nickel with the rest being iron. In one embodiment,the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron and hasa Curie temperature of 277° C. In some embodiments, an alloy is a threecomponent alloy with, for example, chromium, nickel, and iron. Forexample, an alloy may have 6% by weight chromium, 42% by weight nickel,and 52% by weight iron. A 2.5 cm diameter rod of Invar 36 has a turndownratio of approximately 2 to 1 at the Curie temperature. Placing theInvar 36 alloy over a copper core may allow for a smaller rod diameter.A copper core may result in a high turndown ratio. The insulator inlower temperature heater embodiments may be made of a high performancepolymer insulator (such as PFA or PEEK™) when used with alloys with aCurie temperature that is below the melting point or softening point ofthe polymer insulator.

In certain embodiments, a conductor-in-conduit temperature limitedheater is used in lower temperature applications by using lower Curietemperature and/or the phase transformation temperature rangeferromagnetic materials. For example, a lower Curie temperature and/orthe phase transformation temperature range ferromagnetic material may beused for heating inside sucker pump rods. Heating sucker pump rods maybe useful to lower the viscosity of fluids in the sucker pump or rodand/or to maintain a lower viscosity of fluids in the sucker pump rod.Lowering the viscosity of the oil may inhibit sticking of a pump used topump the fluids. Fluids in the sucker pump rod may be heated up totemperatures less than about 250° C. or less than about 300° C.Temperatures need to be maintained below these values to inhibit cokingof hydrocarbon fluids in the sucker pump system.

FIG. 61 depicts an embodiment of a temperature limited heater with a lowtemperature ferromagnetic outer conductor. Outer conductor 502 is glasssealing Alloy 42-6. Alloy 42-6 may be obtained from Carpenter Metals(Reading, Pa., U.S.A.) or Anomet Products, Inc. In some embodiments,outer conductor 502 includes other compositions and/or materials to getvarious Curie temperatures (for example, Carpenter TemperatureCompensator “32” (Curie temperature of 199° C.; available from CarpenterMetals) or Invar 36). In an embodiment, conductive layer 510 is coupled(for example, clad, welded, or brazed) to outer conductor 502.Conductive layer 510 is a copper layer. Conductive layer 510 improves aturndown ratio of outer conductor 502. Jacket 506 is a ferromagneticmetal such as carbon steel. Jacket 506 protects outer conductor 502 froma corrosive environment. Inner conductor 490 may have electricalinsulator 500. Electrical insulator 500 may be a mica tape winding withoverlaid fiberglass braid. In an embodiment, inner conductor 490 andelectrical insulator 500 are a 4/0 MGT-1000 furnace cable or 3/0MGT-1000 furnace cable. 4/0 MGT-1000 furnace cable or 3/0 MGT-1000furnace cable is available from Allied Wire and Cable (Phoenixville,Pa., U.S.A.). In some embodiments, a protective braid such as astainless steel braid may be placed over electrical insulator 500.

Conductive section 504 electrically couples inner conductor 490 to outerconductor 502 and/or jacket 506. In some embodiments, jacket 506 touchesor electrically contacts conductive layer 510 (for example, if theheater is placed in a horizontal configuration). If jacket 506 is aferromagnetic metal such as carbon steel (with a Curie temperature abovethe Curie temperature of outer conductor 502), current will propagateonly on the inside of the jacket. Thus, the outside of the jacketremains electrically uncharged during operation. In some embodiments,jacket 506 is drawn down (for example, swaged down in a die) ontoconductive layer 510 so that a tight fit is made between the jacket andthe conductive layer. The heater may be spooled as coiled tubing forinsertion into a wellbore. In other embodiments, an annular space ispresent between conductive layer 510 and jacket 506, as depicted in FIG.61.

FIG. 62 depicts an embodiment of a temperature limitedconductor-in-conduit heater. Conduit 518 is a hollow sucker rod made ofa ferromagnetic metal such as Alloy 42-6, Alloy 32, Alloy 52, Invar 36,iron-nickel-chromium alloys, iron-nickel alloys, nickel alloys, ornickel-chromium alloys. Inner conductor 490 has electrical insulator500. Electrical insulator 500 is a mica tape winding with overlaidfiberglass braid. In an embodiment, inner conductor 490 and electricalinsulator 500 are a 4/0 MGT-1000 furnace cable or 3/0 MGT-1000 furnacecable. In some embodiments, polymer insulations are used for lowertemperature, temperature limited heaters. In certain embodiments, aprotective braid is placed over electrical insulator 500. Conduit 518has a wall thickness that is greater than the skin depth at the Curietemperature (for example, 2 to 3 times the skin depth at the Curietemperature). In some embodiments, a more conductive conductor iscoupled to conduit 518 to increase the turndown ratio of the heater.

FIG. 63 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater. Conductor 516 iscoupled (for example, clad, coextruded, press fit, drawn inside) toferromagnetic conductor 512. A metallurgical bond between conductor 516and ferromagnetic conductor 512 is favorable. Ferromagnetic conductor512 is coupled to the outside of conductor 516 so that currentpropagates through the skin depth of the ferromagnetic conductor at roomtemperature. Conductor 516 provides mechanical support for ferromagneticconductor 512 at elevated temperatures. Ferromagnetic conductor 512 isiron, an iron alloy (for example, iron with 10% to 27% by weightchromium for corrosion resistance), or any other ferromagnetic material.In one embodiment, conductor 516 is 304 stainless steel andferromagnetic conductor 512 is 446 stainless steel. Conductor 516 andferromagnetic conductor 512 are electrically coupled to conduit 518 withsliding connector 528. Conduit 518 may be a non-ferromagnetic materialsuch as austenitic stainless steel.

FIG. 64 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater. Conduit 518 is coupledto ferromagnetic conductor 512 (for example, clad, press fit, or drawninside of the ferromagnetic conductor). Ferromagnetic conductor 512 iscoupled to the inside of conduit 518 to allow current to propagatethrough the skin depth of the ferromagnetic conductor at roomtemperature. Conduit 518 provides mechanical support for ferromagneticconductor 512 at elevated temperatures. Conduit 518 and ferromagneticconductor 512 are electrically coupled to conductor 516 with slidingconnector 528.

FIG. 65 depicts a cross-sectional view of an embodiment of aconductor-in-conduit temperature limited heater. Conductor 516 maysurround core 508. In an embodiment, conductor 516 is 347H stainlesssteel and core 508 is copper. Conductor 516 and core 508 may be formedtogether as a composite conductor. Conduit 518 may include ferromagneticconductor 512. In an embodiment, ferromagnetic conductor 512 is SumitomoHCM12A or 446 stainless steel. Ferromagnetic conductor 512 may have aSchedule XXH thickness so that the conductor is inhibited fromdeforming. In certain embodiments, conduit 518 also includes jacket 506.Jacket 506 may include corrosion resistant material that inhibitselectrons from flowing away from the heater and into a subsurfaceformation at higher temperatures (for example, temperatures near theCurie temperature and/or the phase transformation temperature range offerromagnetic conductor 512). For example, jacket 506 may be about a 0.4cm thick sheath of 410 stainless steel. Inhibiting electrons fromflowing to the formation may increase the safety of using the heater inthe subsurface formation.

FIG. 66 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor. Insulated conductor 558 may include core 508, electricalinsulator 500, and jacket 506. Jacket 506 may be made of a corrosionresistant material (for example, stainless steel). Endcap 616 may beplaced at an end of insulated conductor 558 to couple core 508 tosliding connector 528. Endcap 616 may be made of non-corrosive,electrically conducting materials such as nickel or stainless steel.Endcap 616 may be coupled to the end of insulated conductor 558 by anysuitable method (for example, welding, soldering, braising). Slidingconnector 528 may electrically couple core 508 and endcap 616 toferromagnetic conductor 512. Conduit 518 may provide support forferromagnetic conductor 512 at elevated temperatures.

FIG. 67 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit temperature limited heater with an insulatedconductor. Insulated conductor 558 includes core 508, electricalinsulator 500, and jacket 506. Jacket 506 is made of a highlyelectrically conductive material such as copper. Core 508 is made of alower temperature ferromagnetic material such as such as Alloy 42-6,Alloy 32, Invar 36, iron-nickel-chromium alloys, iron-nickel alloys,nickel alloys, or nickel-chromium alloys. In certain embodiments, thematerials of jacket 506 and core 508 are reversed so that the jacket isthe ferromagnetic conductor and the core is the highly conductiveportion of the heater. Ferromagnetic material used in jacket 506 or core508 may have a thickness greater than the skin depth at the Curietemperature (for example, 2 to 3 times the skin depth at the Curietemperature). Endcap 616 is placed at an end of insulated conductor 558to couple core 508 to sliding connector 528. Endcap 616 is made ofcorrosion resistant, electrically conducting materials such as nickel orstainless steel. In certain embodiments, conduit 518 is a hollow suckerrod made from, for example, carbon steel.

In certain embodiments, a temperature limited heater includes a flexiblecable (for example, a furnace cable) as the inner conductor. Forexample, the inner conductor may be a 27% nickel-clad or stainlesssteel-clad stranded copper wire with four layers of mica tape surroundedby a layer of ceramic and/or mineral fiber (for example, alumina fiber,aluminosilicate fiber, borosilicate fiber, or aluminoborosilicatefiber). A stainless steel-clad stranded copper wire furnace cable may beavailable from Anomet Products, Inc. The inner conductor may be ratedfor applications at temperatures of 1000° C. or higher. The innerconductor may be pulled inside a conduit. The conduit may be aferromagnetic conduit (for example, a ¾″ Schedule 80 446 stainless steelpipe). The conduit may be covered with a layer of copper, or otherelectrical conductor, with a thickness of about 0.3 cm or any othersuitable thickness. The assembly may be placed inside a support conduit(for example, a 1¼″ Schedule 80 347H or 347HH stainless steel tubular).The support conduit may provide additional creep-rupture strength andprotection for the copper and the inner conductor. For uses attemperatures greater than about 1000° C., the inner copper conductor maybe plated with a more corrosion resistant alloy (for example, Incoloy®825) to inhibit oxidation. In some embodiments, the top of thetemperature limited heater is sealed to inhibit air from contacting theinner conductor.

The temperature limited heater may be a single-phase heater or athree-phase heater. In a three-phase heater embodiment, the temperaturelimited heater has a delta or a wye configuration. Each of the threeferromagnetic conductors in the three-phase heater may be inside aseparate sheath. A connection between conductors may be made at thebottom of the heater inside a splice section. The three conductors mayremain insulated from the sheath inside the splice section.

FIG. 68 depicts an embodiment of a three-phase temperature limitedheater with ferromagnetic inner conductors. Each leg 618 has innerconductor 490, core 508, and jacket 506. Inner conductors 490 areferritic stainless steel or 1% carbon steel. Inner conductors 490 havecore 508. Core 508 may be copper. Each inner conductor 490 is coupled toits own jacket 506. Jacket 506 is a sheath made of a corrosion resistantmaterial (such as 304H stainless steel). Electrical insulator 500 isplaced between inner conductor 490 and jacket 506. Inner conductor 490is ferritic stainless steel or carbon steel with an outside diameter of1.14 cm and a thickness of 0.445 cm. Core 508 is a copper core with a0.25 cm diameter. Each leg 618 of the heater is coupled to terminalblock 620. Terminal block 620 is filled with insulation material 622 andhas an outer surface of stainless steel. Insulation material 622 is, insome embodiments, silicon nitride, boron nitride, magnesium oxide orother suitable electrically insulating material. Inner conductors 490 oflegs 618 are coupled (welded) in terminal block 620. Jackets 506 of legs618 are coupled (welded) to an outer surface of terminal block 620.Terminal block 620 may include two halves coupled around the coupledportions of legs 618.

In some embodiments, the three-phase heater includes three legs that arelocated in separate wellbores. The legs may be coupled in a commoncontacting section (for example, a central wellbore, a connectingwellbore, or a solution filled contacting section). FIG. 69 depicts anembodiment of temperature limited heaters coupled in a three-phaseconfiguration. Each leg 624, 626, 628 may be located in separateopenings 522 in hydrocarbon layer 460. Each leg 624, 626, 628 mayinclude heating element 630. Each leg 624, 626, 628 may be coupled tosingle contacting element 632 in one opening 522. Contacting element 632may electrically couple legs 624, 626, 628 together in a three-phaseconfiguration. Contacting element 632 may be located in, for example, acentral opening in the formation. Contacting element 632 may be locatedin a portion of opening 522 below hydrocarbon layer 460 (for example, inthe underburden). In certain embodiments, magnetic tracking of amagnetic element located in a central opening (for example, opening 522of leg 626) is used to guide the formation of the outer openings (forexample, openings 522 of legs 624 and 628) so that the outer openingsintersect the central opening. The central opening may be formed firstusing standard wellbore drilling methods. Contacting element 632 mayinclude funnels, guides, or catchers for allowing each leg to beinserted into the contacting element.

FIG. 70 depicts an embodiment of three heaters coupled in a three-phaseconfiguration. Conductor “legs” 624, 626, 628 are coupled to three-phasetransformer 634. Transformer 634 may be an isolated three-phasetransformer. In certain embodiments, transformer 634 providesthree-phase output in a wye configuration, as shown in FIG. 70. Input totransformer 634 may be made in any input configuration (such as thedelta configuration shown in FIG. 70). Legs 624, 626, 628 each includelead-in conductors 636 in the overburden of the formation coupled toheating elements 630 in hydrocarbon layer 460. Lead-in conductors 636include copper with an insulation layer. For example, lead-in conductors636 may be a 4-0 copper cables with TEFLON insulation, a copper rod withpolyurethane insulation, or other metal conductors such as bare copperor aluminum. In certain embodiments, lead-in conductors 636 are locatedin an overburden portion of the formation. The overburden portion mayinclude overburden casings 530. Heating elements 630 may be temperaturelimited heater heating elements. In an embodiment, heating elements 630are 410 stainless steel rods (for example, 3.1 cm diameter 410 stainlesssteel rods). In some embodiments, heating elements 630 are compositetemperature limited heater heating elements (for example, 347 stainlesssteel, 410 stainless steel, copper composite heating elements; 347stainless steel, iron, copper composite heating elements; or 410stainless steel and copper composite heating elements). In certainembodiments, heating elements 630 have a length of at least about 10 mto about 2000 m, about 20 m to about 400 m, or about 30 m to about 300m.

In certain embodiments, heating elements 630 are exposed to hydrocarbonlayer 460 and fluids from the hydrocarbon layer. Thus, heating elements630 are “bare metal” or “exposed metal” heating elements. Heatingelements 630 may be made from a material that has an acceptablesulfidation rate at high temperatures used for pyrolyzing hydrocarbons.In certain embodiments, heating elements 630 are made from material thathas a sulfidation rate that decreases with increasing temperature overat least a certain temperature range (for example, 500° C. to 650° C.,530° C. to 650° C., or 550° C. to 650° C.). For example, 410 stainlesssteel may have a sulfidation rate that decreases with increasingtemperature between 530° C. and 650° C. Using such materials reducescorrosion problems due to sulfur-containing gases (such as H₂S) from theformation. In certain embodiments, heating elements 630 are made frommaterial that has a sulfidation rate below a selected value in atemperature range. In some embodiments, heating elements 630 are madefrom material that has a sulfidation rate at most about 25 mils per yearat a temperature between about 800° C. and about 880° C. In someembodiments, the sulfidation rate is at most about 35 mils per year at atemperature between about 800° C. and about 880° C., at most about 45mils per year at a temperature between about 800° C. and about 880° C.,or at most about 55 mils per year at a temperature between about 800° C.and about 880° C. Heating elements 630 may also be substantially inertto galvanic corrosion.

In some embodiments, heating elements 630 have a thin electricallyinsulating layer such as aluminum oxide or thermal spray coated aluminumoxide. In some embodiments, the thin electrically insulating layer is aceramic composition such as an enamel coating. Enamel coatings include,but are not limited to, high temperature porcelain enamels. Hightemperature porcelain enamels may include silicon dioxide, boron oxide,alumina, and alkaline earth oxides (CaO or MgO), and minor amounts ofalkali oxides (Na₂O, K₂O, LiO). The enamel coating may be applied as afinely ground slurry by dipping the heating element into the slurry orspray coating the heating element with the slurry. The coated heatingelement is then heated in a furnace until the glass transitiontemperature is reached so that the slurry spreads over the surface ofthe heating element and makes the porcelain enamel coating. Theporcelain enamel coating contracts when cooled below the glasstransition temperature so that the coating is in compression. Thus, whenthe coating is heated during operation of the heater, the coating isable to expand with the heater without cracking.

The thin electrically insulating layer has low thermal impedanceallowing heat transfer from the heating element to the formation whileinhibiting current leakage between heating elements in adjacent openingsand/or current leakage into the formation. In certain embodiments, thethin electrically insulating layer is stable at temperatures above atleast 350° C., above 500° C., or above 800° C. In certain embodiments,the thin electrically insulating layer has an emissivity of at least0.7, at least 0.8, or at least 0.9. Using the thin electricallyinsulating layer may allow for long heater lengths in the formation withlow current leakage.

Heating elements 630 may be coupled to contacting elements 632 at ornear the underburden of the formation. Contacting elements 632 arecopper or aluminum rods or other highly conductive materials. In certainembodiments, transition sections 638 are located between lead-inconductors 636 and heating elements 630, and/or between heating elements630 and contacting elements 632. Transition sections 638 may be made ofa conductive material that is corrosion resistant such as 347 stainlesssteel over a copper core. In certain embodiments, transition sections638 are made of materials that electrically couple lead-in conductors636 and heating elements 630 while providing little or no heat output.Thus, transition sections 638 help to inhibit overheating of conductorsand insulation used in lead-in conductors 636 by spacing the lead-inconductors from heating elements 630. Transition section 638 may have alength of between about 3 m and about 9 m (for example, about 6 m).

Contacting elements 632 are coupled to contactor 640 in contactingsection 642 to electrically couple legs 624, 626, 628 to each other. Insome embodiments, contact solution 644 (for example, conductive cement)is placed in contacting section 642 to electrically couple contactingelements 632 in the contacting section. In certain embodiments, legs624, 626, 628 are substantially parallel in hydrocarbon layer 460 andleg 624 continues substantially vertically into contacting section 642.The other two legs 626, 628 are directed (for example, by directionallydrilling the wellbores for the legs) to intercept leg 624 in contactingsection 642.

Each leg 624, 626, 628 may be one leg of a three-phase heater embodimentso that the legs are substantially electrically isolated from otherheaters in the formation and are substantially electrically isolatedfrom the formation. Legs 624, 626, 628 may be arranged in a triangularpattern so that the three legs form a triangular shaped three-phaseheater. In an embodiment, legs 624, 626, 628 are arranged in atriangular pattern with 12 m spacing between the legs (each side of thetriangle has a length of 12 m).

In certain embodiments, the thin electrically insulating layer allowsfor relatively long, substantially horizontal heater leg lengths in thehydrocarbon layer with a substantially u-shaped heater. FIG. 71 depictsa side-view representation of an embodiment of a substantially u-shapedthree-phase heater. First ends of legs 624, 626, 628 are coupled totransformer 634 at first location 646. In an embodiment, transformer 634is a three-phase AC transformer. Ends of legs 624, 626, 628 areelectrically coupled together with connector 648 at second location 650.Connector 648 electrically couples the ends of legs 624, 626, 628 sothat the legs can be operated in a three-phase configuration. In certainembodiments, legs 624, 626, 628 are coupled to operate in a three-phasewye configuration. In certain embodiments, legs 624, 626, 628 aresubstantially parallel in hydrocarbon layer 460. In certain embodiments,legs 624, 626, 628 are arranged in a triangular pattern in hydrocarbonlayer 460. In certain embodiments, heating elements 630 include a thinelectrically insulating material (such as a porcelain enamel coating) toinhibit current leakage from the heating elements. In certainembodiments, legs 624, 626, 628 are electrically coupled so that thelegs are substantially electrically isolated from other heaters in theformation and are substantially electrically isolated from theformation.

In certain embodiments, overburden casings (for example, overburdencasings 530, depicted in FIGS. 70 and 71) in overburden 458 includematerials that inhibit ferromagnetic effects in the casings. Inhibitingferromagnetic effects in casings 530 reduces heat losses to theoverburden. In some embodiments, casings 530 may include non-metallicmaterials such as fiberglass, polyvinylchloride (PVC), chlorinatedpolyvinylchloride (CPVC), or high-density polyethylene (HDPE). HDPEswith working temperatures in a range for use in overburden 458 includeHDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.). Anon-metallic casing may also eliminate the need for an insulatedoverburden conductor. In some embodiments, casings 530 include carbonsteel coupled on the inside diameter of a non-ferromagnetic metal (forexample, carbon steel clad with copper or aluminum) to inhibitferromagnetic effects or inductive effects in the carbon steel. Othernon-ferromagnetic metals include, but are not limited to, manganesesteels with at least 10% by weight manganese, iron aluminum alloys withat least 18% by weight aluminum, and austentitic stainless steels suchas 304 stainless steel or 316 stainless steel.

In certain embodiments, one or more non-ferromagnetic materials used incasings 530 are used in a wellhead coupled to the casings and legs 624,626, 628. Using non-ferromagnetic materials in the wellhead inhibitsundesirable heating of components in the wellhead. In some embodiments,a purge gas (for example, carbon dioxide, nitrogen or argon) isintroduced into the wellhead and/or inside of casings 530 to inhibitreflux of heated gases into the wellhead and/or the casings.

In certain embodiments, one or more of legs 624, 626, 628 are installedin the formation using coiled tubing. In certain embodiments, coiledtubing is installed in the formation, the leg is installed inside thecoiled tubing, and the coiled tubing is pulled out of the formation toleave the leg installed in the formation. The leg may be placedconcentrically inside the coiled tubing. In some embodiments, coiledtubing with the leg inside the coiled tubing is installed in theformation and the coiled tubing is removed from the formation to leavethe leg installed in the formation. The coiled tubing may extend only toa junction of hydrocarbon layer 460 and contacting section 642 (as shownin FIG. 70) or to a point at which the leg begins to bend in thecontacting section.

FIG. 72 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in the formation. Each triad652 includes legs A, B, C (which may correspond to legs 624, 626, 628depicted in FIGS. 70 and 71) that are electrically coupled by linkage654. Each triad 652 is coupled to its own electrically isolatedthree-phase transformer so that the triads are substantiallyelectrically isolated from each other. Electrically isolating the triadsinhibits net current flow between triads.

The phases of each triad 652 may be arranged so that legs A, B, Ccorrespond between triads as shown in FIG. 72. In FIG. 72, legs A, B, Care arranged such that a phase leg (for example, leg A) in a given triadis about two triad heights from a same phase leg (leg A) in an adjacenttriad. The triad height is the distance from a vertex of the triad to amidpoint of the line intersecting the other two vertices of the triad.In certain embodiments, the phases of triads 652 are arranged to inhibitnet current flow between individual triads. There may be some leakage ofcurrent within an individual triad but little net current flows betweentwo triads due to the substantial electrical isolation of the triadsand, in certain embodiments, the arrangement of the triad phases.

In the early stages of heating, an exposed heating element (for example,heating element 630 depicted in FIGS. 70 and 71) may leak some currentto water or other fluids that are electrically conductive in theformation so that the formation itself is heated. After water or otherelectrically conductive fluids are removed from the wellbore (forexample, vaporized or produced), the heating elements becomeelectrically isolated from the formation. Later, when water is removedfrom the formation, the formation becomes even more electricallyresistant and heating of the formation occurs even more predominantlyvia thermally conductive and/or radiative heating. Typically, theformation (the hydrocarbon layer) has an initial electrical resistancethat averages at least 10 ohm·m. In some embodiments, the formation hasan initial electrical resistance of at least 100 ohm·m or of at least300 ohm·m.

Using the temperature limited heaters as the heating elements limits theeffect of water saturation on heater efficiency. With water in theformation and in heater wellbores, there is a tendency for electricalcurrent to flow between heater elements at the top of the hydrocarbonlayer where the voltage is highest and cause uneven heating in thehydrocarbon layer. This effect is inhibited with temperature limitedheaters because the temperature limited heaters reduce localizedoverheating in the heating elements and in the hydrocarbon layer.

In certain embodiments, production wells are placed at a location atwhich there is relatively little or zero voltage potential. Thislocation minimizes stray potentials at the production well. Placingproduction wells at such locations improves the safety of the system andreduces or inhibits undesired heating of the production wells caused byelectrical current flow in the production wells. FIG. 73 depicts a topview representation of the embodiment depicted in FIG. 72 withproduction wells 206. In certain embodiments, production wells 206 arelocated at or near center of triad 652. In certain embodiments,production wells 206 are placed at a location between triads at whichthere is relatively little or zero voltage potential (at a location atwhich voltage potentials from vertices of three triads average out torelatively little or zero voltage potential). For example, productionwell 206 may be at a location equidistant from legs A of one triad, legB of a second triad, and leg C of a third triad, as shown in FIG. 73.

FIG. 74 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern in theformation. FIG. 75 depicts a top view representation of an embodiment ofa hexagon from FIG. 74. Hexagon 656 includes two triads of heaters. Thefirst triad includes legs A1, B1, C1 electrically coupled together bylinkages 654 in a three-phase configuration. The second triad includeslegs A2, B2, C2 electrically coupled together by linkages 654 in athree-phase configuration. The triads are arranged so that correspondinglegs of the triads (for example, A1 and A2, B1 and B2, C1 and C2) are atopposite vertices of hexagon 656. The triads are electrically coupledand arranged so that there is relatively little or zero voltagepotential at or near the center of hexagon 656.

Production well 206 may be placed at or near the center of hexagon 656.Placing production well 206 at or near the center of hexagon 656 placesthe production well at a location that reduces or inhibits undesiredheating due to electromagnetic effects caused by electrical current flowin the legs of the triads and increases the safety of the system. Havingtwo triads in hexagon 656 provides for redundant heating aroundproduction well 206. Thus, if one triad fails or has to be turned off,production well 206 still remains at a center of one triad.

As shown in FIG. 74, hexagons 656 may be arranged in a pattern in theformation such that adjacent hexagons are offset. Using electricallyisolated transformers on adjacent hexagons may inhibit electricalpotentials in the formation so that little or no net current leaksbetween hexagons.

Triads of heaters and/or heater legs may be arranged in any shape ordesired pattern. For example, as described above, triads may includethree heaters and/or heater legs arranged in an equilateral triangularpattern. In some embodiments, triads include three heaters and/or heaterlegs arranged in other triangular shapes (for example, an isoscelestriangle or a right angle triangle). In some embodiments, heater legs inthe triad cross each other (for example, criss-cross) in the formation.In certain embodiments, triads includes three heaters and/or heater legsarranged sequentially along a straight line.

FIG. 76 depicts an embodiment with triads coupled to a horizontalconnector well. Triad 652A includes legs 624A, 626A, 628A. Triad 652Bincludes legs 624B, 626B, 628B. Legs 624A, 626A, 628A and legs 624B,626B, 628B may be arranged along a straight line on the surface of theformation. In some embodiments, legs 624A, 626A, 628A are arranged alonga straight line and offset from legs 624B, 626B, 628B, which may bearranged along a straight line. Legs 624A, 626A, 628A and legs 624B,626B, 628B include heating elements 630 located in hydrocarbon layer460. Lead-in conductors 636 couple heating elements 630 to the surfaceof the formation. Heating elements 630 are coupled to contactingelements 632 at or near the underburden of the formation. In certainembodiments, transition sections (for example, transition sections 638depicted in FIG. 70) are located between lead-in conductors 636 andheating elements 630, and/or between heating elements 630 and contactingelements 632.

Contacting elements 632 are coupled to contactor 640 in contactingsection 642 to electrically couple legs 624A, 626A, 628A to each otherto form triad 652A and electrically couple legs 624B, 626B, 628B to eachother to form triad 652B. In certain embodiments, contactor 640 is aground conductor so that triad 652A and/or triad 652B may be coupled inthree-phase wye configurations. In certain embodiments, triad 652A andtriad 652B are electrically isolated from each other. In someembodiments, triad 652A and triad 652B are electrically coupled to eachother (for example, electrically coupled in series or parallel).

In certain embodiments, contactor 640 is a substantially horizontalcontactor located in contacting section 642. Contactor 640 may be acasing or a solid rod placed in a wellbore drilled substantiallyhorizontally in contacting section 642. Legs 624A, 626A, 628A and legs624B, 626B, 628B may be electrically coupled to contactor 640 by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to contactor 640 (forexample, by welding or brazing the containers to the contactor); legs624A, 626A, 628A and legs 624B, 626B, 628B are placed inside thecontainers; and the thermite powder is activated to electrically couplethe legs to the contactor. The containers may be coupled to contactor640 by, for example, placing the containers in holes or recesses incontactor 640 or coupled to the outside of the contactor and thenbrazing or welding the containers to the contactor.

As shown in FIG. 70, contacting elements 632 of legs 624, 626, 628 maybe coupled using contactor 640 and/or contact solution 644. In certainembodiments, contacting elements 632 of legs 624, 626, 628 arephysically coupled, for example, through soldering, welding, or othertechniques. FIGS. 77 and 78 depict embodiments for coupling contactingelements 632 of legs 624, 626, 628. Legs 626, 628 may enter the wellboreof leg 624 from any direction desired. In one embodiment, legs 626, 628enter the wellbore of leg 624 from approximately the same side of thewellbore, as shown in FIG. 77. In an alternative embodiment, legs 626,628 enter the wellbore of leg 624 from approximately opposite sides ofthe wellbore, as shown in FIG. 78.

Container 658 is coupled to contacting element 632 of leg 624. Container658 may be soldered, welded, or otherwise electrically coupled tocontacting element 632. Container 658 is a metal can or other containerwith at least one opening for receiving one or more contacting elements632. In an embodiment, container 658 is a can that has an opening forreceiving contacting elements 632 from legs 626, 628, as shown in FIG.77. In certain embodiments, wellbores for legs 626, 628 are drilledparallel to the wellbore for leg 624 through the hydrocarbon layer thatis to be heated and directionally drilled below the hydrocarbon layer tointercept wellbore for leg 624 at an angle between about 100 and about200 from vertical. Wellbores may be directionally drilled using knowntechniques such as techniques used by Vector Magnetics, Inc.

In some embodiments, contacting elements 632 contact the bottom ofcontainer 658. Contacting elements 632 may contact the bottom ofcontainer 658 and/or each other to promote electrical connection betweenthe contacting elements and/or the container. In certain embodiments,end portions of contacting elements 632 are annealed to a “dead soft”condition to facilitate entry into container 658. In some embodiments,rubber or other softening material is attached to end portions ofcontacting elements 632 to facilitate entry into container 658. In someembodiments, contacting elements 632 include reticulated sections, suchas knuckle-joints or limited rotation knuckle-joints, to facilitateentry into container 658.

In certain embodiments, an electrical coupling material is placed incontainer 658. The electrical coupling material may line the walls ofcontainer 658 or fill up a portion of the container. In certainembodiments, the electrical coupling material lines an upper portion,such as the funnel-shaped portion shown in FIG. 79, of container 658.The electrical coupling material includes one or more materials thatwhen activated (for example, heated, ignited, exploded, combined, mixed,and/or reacted) form a material that electrically couples one or moreelements to each other. In an embodiment, the coupling materialelectrically couples contacting elements 632 in container 658. In someembodiments, the coupling material metallically bonds to contactingelements 632 so that the contacting elements are metallically bonded toeach other. In some embodiments, container 658 is initially filled witha high viscosity water-based polymer fluid to inhibit drill cuttings orother materials from entering the container prior to using the couplingmaterial to couple the contacting elements. The polymer fluid may be,but is not limited to, a cross-linked XC polymer (available from BaroidIndustrial Drilling Products (Houston, Tex., U.S.A.), a frac gel, or across-linked polyacrylamide gel.

In certain embodiments, the electrical coupling material is alow-temperature solder that melts at relatively low temperature and whencooled forms an electrical connection to exposed metal surfaces. Incertain embodiments, the electrical coupling material is a solder thatmelts at a temperature below the boiling point of water at the depth ofcontainer 658. In one embodiment, the electrical coupling material is a58% by weight bismuth and 42% by weight tin eutectic alloy. Otherexamples of such solders include, but are not limited to, a 54% byweight bismuth, 16% by weight tin, 30% by weight indium alloy, and a 48%by weight tin, 52% by weight indium alloy. Such low-temperature solderswill displace water upon melting so that the water moves to the top ofcontainer 658. Water at the top of container 658 may inhibit heattransfer into the container and thermally insulate the low-temperaturesolder so that the solder remains at cooler temperatures and does notmelt during heating of the formation using the heating elements.

Container 658 may be heated to activate the electrical coupling materialto facilitate the connection of contacting elements 632. In certainembodiments, container 658 is heated to melt the electrical couplingmaterial in the container. The electrical coupling material flows whenmelted and surrounds contacting elements 632 in container 658. Any waterwithin container 658 will float to the surface of the metal when themetal is melted. The electrical coupling material is allowed to cool andelectrically connects contacting elements 632 to each other. In certainembodiments, contacting elements 632 of legs 626, 628, the inside wallsof container 658, and/or the bottom of the container are initiallypre-tinned with electrical coupling material.

End portions of contacting elements 632 of legs 624, 626, 628 may haveshapes and/or features that enhance the electrical connection betweenthe contacting elements and the coupling material. The shapes and/orfeatures of contacting elements 632 may also enhance the physicalstrength of the connection between the contacting elements and thecoupling material (for example, the shape and/or features of thecontacting element may anchor the contacting element in the couplingmaterial). Shapes and/or features for end portions of contactingelements 632 include, but are not limited to, grooves, notches, holes,threads, serrated edges, openings, and hollow end portions. In certainembodiments, the shapes and/or features of the end portions ofcontacting elements 632 are initially pre-tinned with electricalcoupling material.

FIG. 79 depicts an embodiment of container 658 with an initiator formelting the coupling material. The initiator is an electrical resistanceheating element or any other element for providing heat that activatesor melts the coupling material in container 658. In certain embodiments,heating element 660 is a heating element located in the walls ofcontainer 658. In some embodiments, heating element 660 is located onthe outside of container 658. Heating element 660 may be, for example, anichrome wire, a mineral-insulated conductor, a polymer-insulatedconductor, a cable, or a tape that is inside the walls of container 658or on the outside of the container. In some embodiments, heating element660 wraps around the inside walls of the container or around the outsideof the container. Lead-in wire 662 may be coupled to a power source atthe surface of the formation. Lead-out wire 664 may be coupled to thepower source at the surface of the formation. Lead-in wire 662 and/orlead-out wire 664 may be coupled along the length of leg 624 formechanical support. Lead-in wire 662 and/or lead-out wire 664 may beremoved from the wellbore after melting the coupling material. Lead-inwire 662 and/or lead-out wire 664 may be reused in other wellbores.

In some embodiments, container 658 has a funnel-shape, as shown in FIG.79, that facilitates the entry of contacting elements 632 into thecontainer. In certain embodiments, container 658 is made of or includescopper for good electrical and thermal conductivity. A copper container658 makes good electrical contact with contacting elements (such ascontacting elements 632 shown in FIGS. 77 and 78) if the contactingelements touch the walls and/or bottom of the container.

FIG. 80 depicts an embodiment of container 658 with bulbs on contactingelements 632. Protrusions 666 may be coupled to a lower portion ofcontacting elements 632. Protrusions 668 may be coupled to the innerwall of container 658. Protrusions 666, 668 may be made of copper oranother suitable electrically conductive material. Lower portion ofcontacting element 632 of leg 628 may have a bulbous shape, as shown inFIG. 80. In certain embodiments, contacting element 632 of leg 628 isinserted into container 658. Contacting element 632 of leg 626 isinserted after insertion of contacting element 632 of leg 628. Both legsmay then be pulled upwards simultaneously. Protrusions 666 may lockcontacting elements 632 into place against protrusions 668 in container658. A friction fit is created between contacting elements 632 andprotrusions 666, 668.

Lower portions of contacting elements 632 inside container 658 mayinclude 410 stainless steel or any other heat generating electricalconductor. Portions of contacting elements 632 above the heat generatingportions of the contacting elements include copper or another highlyelectrically conductive material. Centralizers 524 may be located on theportions of contacting elements 632 above the heat generating portionsof the contacting elements. Centralizers 524 inhibit physical andelectrical contact of portions of contacting elements 632 above the heatgenerating portions of the contacting elements against walls ofcontainer 658.

When contacting elements 632 are locked into place inside container 658by protrusions 666, 668, at least some electrical current may be passbetween the contacting elements through the protrusions. As electricalcurrent is passed through the heat generating portions of contactingelements 632, heat is generated in container 658. The generated heat maymelt coupling material 670 located inside container 658. Water incontainer 658 may boil. The boiling water may convect heat to upperportions of container 658 and aid in melting of coupling material 670.Walls of container 658 may be thermally insulated to reduce heat lossesout of the container and allow the inside of the container to heat upfaster. Coupling material 670 flows down into the lower portion ofcontainer 658 as the coupling material melts. Coupling material 670fills the lower portion of container 658 until the heat generatingportions of contacting elements 632 are below the fill line of thecoupling material. Coupling material 670 then electrically couples theportions of contacting elements 632 above the heat generating portionsof the contacting elements. The resistance of contacting elements 632decreases at this point and heat is no longer generated in thecontacting elements and the coupling materials is allowed to cool.

In certain embodiments, container 658 includes insulation layer 672inside the housing of the container. Insulation layer 672 may includethermally insulating materials to inhibit heat losses from the canister.For example, insulation layer 672 may include magnesium oxide, siliconnitride, or other thermally insulating materials that withstandoperating temperatures in container 658. In certain embodiments,container 658 includes liner 674 on an inside surface of the container.Liner 674 may increase electrical conductivity inside container 658.Liner 674 may include electrically conductive materials such as copperor aluminum.

FIG. 81 depicts an alternative embodiment for container 658. Couplingmaterial in container 658 includes powder 676. Powder 676 is a chemicalmixture that produces a molten metal product from a reaction of thechemical mixture. In an embodiment, powder 676 is thermite powder.Powder 676 lines the walls of container 658 and/or is placed in thecontainer. Igniter 678 is placed in powder 676. Igniter 678 may be, forexample, a magnesium ribbon that when activated ignites the reaction ofpowder 676. When powder 676 reacts, a molten metal produced by thereaction flows and surrounds contacting elements 632 placed in container658. When the molten metal cools, the cooled metal electrically connectscontacting elements 632. In some embodiments, powder 676 is used incombination with another coupling material, such as a low-temperaturesolder, to couple contacting elements 632. The heat of reaction ofpowder 676 may be used to melt the low temperature-solder.

In certain embodiments, an explosive element is placed in container 658,depicted in FIG. 77 or FIG. 81. The explosive element may be, forexample, a shaped charge explosive or other controlled explosiveelement. The explosive element may be exploded to crimp contactingelements 632 and/or container 658 together so that the contactingelements and the container are electrically connected. In someembodiments, an explosive element is used in combination with anelectrical coupling material such as low-temperature solder or thermitepowder to electrically connect contacting elements 632.

FIG. 82 depicts an alternative embodiment for coupling contactingelements 632 of legs 624, 626, 628. Container 658A is coupled tocontacting element 632 of leg 626. Container 658B is coupled tocontacting element 632 of leg 628. Container 658B is sized and shaped tobe placed inside container 658A. Container 658C is coupled to contactingelement 632 of leg 624. Container 658C is sized and shaped to be placedinside container 658B. In some embodiments, contacting element 632 ofleg 624 is placed in container 658B without a container attached to thecontacting element. One or more of containers 658A, 658B, 658C may befilled with a coupling material that is activated to facilitate anelectrical connection between contacting elements 632 as describedabove.

FIG. 83 depicts a cross-sectional representation of an embodiment forcoupling contacting elements using temperature limited heating elements.Contacting elements 632 of legs 624, 626, 628 may have insulation 680 onportions of the contacting elements above container 658. Container 658may be shaped and/or have guides at the top to guide the insertion ofcontacting elements 632 into the container. Coupling material 670 may belocated inside container 658 at or near a top of the container. Couplingmaterial 670 may be, for example, a solder material. In someembodiments, inside walls of container 658 are pre-coated with couplingmaterial or another electrically conductive material such as copper oraluminum. Centralizers 524 may be coupled to contacting elements 632 tomaintain a spacing of the contacting elements in container 658.Container 658 may be tapered at the bottom to push lower portions ofcontacting elements 632 together for at least some electrical contactbetween the lower portions of the contacting elements.

Heating elements 682 may be coupled to portions of contacting elements632 inside container 658. Heating elements 682 may include ferromagneticmaterials such as iron or stainless steel. In an embodiment, heatingelements 682 are iron cylinders clad onto contacting elements 632.Heating elements 682 may be designed with dimensions and materials thatwill produce a desired amount of heat in container 658. In certainembodiments, walls of container 658 are thermally insulated withinsulation layer 672, as shown in FIG. 83 to inhibit heat loss from thecontainer. Heating elements 682 may be spaced so that contactingelements 632 have one or more portions of exposed material insidecontainer 658. The exposed portions include exposed copper or anothersuitable highly electrically conductive material. The exposed portionsallow for better electrical contact between contacting elements 632 andcoupling material 670 after the coupling material has been melted, fillscontainer 658, and is allowed to cool.

In certain embodiments, heating elements 682 operate as temperaturelimited heaters when a time-varying current is applied to the heatingelements. For example, a 400 Hz, AC current may be applied to heatingelements 682. Application of the time-varying current to contactingelements 632 causes heating elements 682 to generate heat and meltcoupling material 670. Heating elements 682 may operate as temperaturelimited heating elements with a self-limiting temperature selected sothat coupling material 670 is not overheated. As coupling material 670fills container 658, the coupling material makes electrical contactbetween portions of exposed material on contacting elements 632 andelectrical current begins to flow through the exposed material portionsrather than heating elements 682. Thus, the electrical resistancebetween the contacting elements decreases. As this occurs, temperaturesinside container 658 begin to decrease and coupling material 670 isallowed to cool to create an electrical contacting section betweencontacting elements 632. In certain embodiments, electrical power tocontacting elements 632 and heating elements 682 is turned off when theelectrical resistance in the system falls below a selected resistance.The selected resistance may indicate that the coupling material hassufficiently electrically connected the contacting elements. In someembodiments, electrical power is supplied to contacting elements 632 andheating elements 682 for a selected amount of time that is determined toprovide enough heat to melt the mass of coupling material 670 providedin container 658.

FIG. 84 depicts a cross-sectional representation of an alternativeembodiment for coupling contacting elements using temperature limitedheating elements. Contacting element 632 of leg 624 may be coupled tocontainer 658 by welding, brazing, or another suitable method. Lowerportion of contacting element 632 of leg 628 may have a bulbous shape.Contacting element 632 of leg 628 is inserted into container 658.Contacting element 632 of leg 626 is inserted after insertion ofcontacting element 632 of leg 628. Both legs may then be pulled upwardssimultaneously. Protrusions 668 may lock contacting elements 632 intoplace and a friction fit may be created between the contacting elements632. Centralizers 524 may inhibit electrical contact between upperportions of contacting elements 632.

Time-varying electrical current may be applied to contacting elements632 so that heating elements 682 generate heat. The generated heat maymelt coupling material 670 located in container 658 and be allowed tocool, as described for the embodiment depicted in FIG. 83. After coolingof coupling material 670, contacting elements 632 of legs 626, 628,shown in FIG. 84, are electrically coupled in container 658 with thecoupling material. In some embodiments, lower portions of contactingelements 632 have protrusions or openings that anchor the contactingelements in cooled coupling material. Exposed portions of the contactingelements provide a low electrical resistance path between the contactingelements and the coupling material.

FIG. 85 depicts a cross-sectional representation of another embodimentfor coupling contacting elements using temperature limited heatingelements. Contacting element 632 of leg 624 may be coupled to container658 by welding, brazing, or another suitable method. Lower portion ofcontacting element 632 of leg 628 may have a bulbous shape. Contactingelement 632 of leg 628 is inserted into container 658. Contactingelement 632 of leg 626 is inserted after insertion of contacting element632 of leg 628. Both legs may then be pulled upwards simultaneously.Protrusions 668 may lock contacting elements 632 into place and afriction fit may be created between the contacting elements 632.Centralizers 524 may inhibit electrical contact between upper portionsof contacting elements 632.

End portions 632B of contacting elements 632 may be made of aferromagnetic material such as 410 stainless steel. Portions 632A mayinclude non-ferromagnetic electrically conductive material such ascopper or aluminum. Time-varying electrical current may be applied tocontacting elements 632 so that end portions 632B generate heat due tothe resistance of the end portions. The generated heat may melt couplingmaterial 670 located in container 658 and be allowed to cool, asdescribed for the embodiment depicted in FIG. 83. After cooling ofcoupling material 670, contacting elements 632 of legs 626, 628, shownin FIG. 84, are electrically coupled in container 658 with the couplingmaterial. Portions 632A may be below the fill line of coupling material670 so that these portions of the contacting elements provide a lowelectrical resistance path between the contacting elements and thecoupling material.

FIG. 86 depicts a side view representation of an alternative embodimentfor coupling contacting elements of three legs of a heater. FIG. 87depicts a top view representation of the alternative embodiment forcoupling contacting elements of three legs of a heater depicted in FIG.86. Container 658 may include inner container 684 and outer container686. Inner container 684 may be made of copper or another malleable,electrically conductive metal such as aluminum. Outer container 686 maybe made of a rigid material such as stainless steel. Outer container 686protects inner container 684 and its contents from environmentalconditions outside of container 658.

Inner container 684 may be substantially solid with two openings 688 and690. Inner container 684 is coupled to contacting element 632 of leg624. For example, inner container 684 may be welded or brazed tocontacting element 632 of leg 624. Openings 688, 690 are shaped to allowcontacting elements 632 of legs 626, 628 to enter the openings as shownin FIG. 86. Funnels or other guiding mechanisms may be coupled to theentrances to openings 688, 690 to guide contacting elements 632 of legs626, 628 into the openings. Contacting elements 632 of legs 624, 626,628 may be made of the same material as inner container 684.

Explosive elements 700 may be coupled to the outer wall of innercontainer 684. In certain embodiments, explosive elements 700 areelongated explosive strips that extend along the outer wall of innercontainer 684. Explosive elements 700 may be arranged along the outerwall of inner container 684 so that the explosive elements are alignedat or near the centers of contacting elements 632, as shown in FIG. 87.Explosive elements 700 are arranged in this configuration so that energyfrom the explosion of the explosive elements causes contacting elements632 to be pushed towards the center of inner container 684.

Explosive elements 700 may be coupled to battery 702 and timer 704.Battery 702 may provide power to explosive elements 700 to initiate theexplosion. Timer 704 may be used to control the time for ignitingexplosive elements 700. Battery 702 and timer 704 may be coupled totriggers 706. Triggers 706 may be located in openings 688, 690.Contacting elements 632 may set off triggers 706 as the contactingelements are placed into openings 688, 690. When both triggers 706 inopenings 688, 690 are triggered, timer 704 may initiate a countdownbefore igniting explosive elements 700. Thus, explosive elements 700 arecontrolled to explode only after contacting elements 632 are placedsufficiently into openings 688, 690 so that electrical contact may bemade between the contacting elements and inner container 684 after theexplosions. Explosion of explosive elements 700 crimps contactingelements 632 and inner container 684 together to make electrical contactbetween the contacting elements and the inner container. In certainembodiments, explosive elements 700 fire from the bottom towards the topof inner container 684. Explosive elements 700 may be designed with alength and explosive power (band width) that gives an optimum electricalcontact between contacting elements 632 and inner container 684:

In some embodiments, triggers 706, battery 702, and timer 704 may beused to ignite a powder (for example, copper thermite powder) inside acontainer (for example, container 658 or inner container 684). Battery702 may charge a magnesium ribbon or other ignition device in the powderto initiate reaction of the powder to produce a molten metal product.The molten metal product may flow and then cool to electrically contactthe contacting elements.

In certain embodiments, electrical connection is made between contactingelements 632 through mechanical means. FIG. 88 depicts an embodiment ofcontacting element 632 with a brush contactor. Brush contactor 708 iscoupled to a lower portion of contacting element 632. Brush contactor708 may be made of a malleable, electrically conductive material such ascopper or aluminum. Brush contactor 708 may be a webbing of materialthat is compressible and/or flexible. Centralizer 524 may be located ator near the bottom of contacting element 632.

FIG. 89 depicts an embodiment for coupling contacting elements 632 withbrush contactors 708. Brush contactors 708 are coupled to eachcontacting element 632 of legs 624, 626, 628. Brush contactors 708compress against each other and interlace to electrically couplecontacting elements 632 of legs 624, 626, 628. Centralizers 524 maintainspacing between contacting elements 632 of legs 624, 626, 628 so thatinterference and/or clearance issues between the contacting elements areinhibited.

In certain embodiments, contacting elements 632 (depicted in FIGS.77-89) are coupled in a zone of the formation that is cooler than thelayer of the formation to be heated (for example, in the underburden ofthe formation). Contacting elements 632 are coupled in a cooler zone toinhibit melting of the coupling material and/or degradation of theelectrical connection between the elements during heating of thehydrocarbon layer above the cooler zone. In certain embodiments,contacting elements 632 are coupled in a zone that is at least about 3m, at least about 6 m, or at least about 9 m below the layer of theformation to be heated. In some embodiments, the zone has a standingwater level that is above a depth of containers 658.

In certain embodiments, two legs in separate wellbores intercept in asingle contacting section. FIG. 90 depicts an embodiment of twotemperature limited heaters coupled in a single contacting section. Legs624 and 626 include one or more heating elements 630. Heating elements630 may include one or more electrical conductors. In certainembodiments, legs 624 and 626 are electrically coupled in a single-phaseconfiguration with one leg positively biased versus the other leg sothat current flows downhole through one leg and returns through theother leg.

Heating elements 630 in legs 624 and 626 may be temperature limitedheaters. In certain embodiments, heating elements 630 are solid rodheaters. For example, heating elements 630 may be rods made of a singleferromagnetic conductor element or composite conductors that includeferromagnetic material. During initial heating when water is present inthe formation being heated, heating elements 630 may leak current intohydrocarbon layer 460. The current leaked into hydrocarbon layer 460 mayresistively heat the hydrocarbon layer.

In some embodiments (for example, in oil shale formations), heatingelements 630 do not need support members. Heating elements 630 may bepartially or slightly bent, curved, made into an S-shape, or made into ahelical shape to allow for expansion and/or contraction of the heatingelements. In certain embodiments, solid rod heating elements 630 areplaced in small diameter wellbores (for example, about 3%″ (about 9.5cm) diameter wellbores). Small diameter wellbores may be less expensiveto drill or form than larger diameter wellbores, and there will be lesscuttings to dispose of.

In certain embodiments, portions of legs 624 and 626 in overburden 458have insulation (for example, polymer insulation) to inhibit heating theoverburden. Heating elements 630 may be substantially vertical andsubstantially parallel to each other in hydrocarbon layer 460. At ornear the bottom of hydrocarbon layer 460, leg 624 may be directionallydrilled towards leg 626 to intercept leg 626 in contacting section 642.Drilling two wellbores to intercept each other may be easier and lessexpensive than drilling three or more wellbores to intercept each other.The depth of contacting section 642 depends on the length of bend in leg624 needed to intercept leg 626. For example, for a 40 ft (about 12 m)spacing between vertical portions of legs 624 and 626, about 200 ft(about 61 m) is needed to allow the bend of leg 624 to intercept leg626. Coupling two legs may require a thinner contacting section 642 thancoupling three or more legs in the contacting section.

FIG. 91 depicts an embodiment for coupling legs 624 and 626 incontacting section 642. Heating elements 630 are coupled to contactingelements 632 at or near junction of contacting section 642 andhydrocarbon layer 460. Contacting elements 632 may be copper or anothersuitable electrical conductor. In certain embodiments, contactingelement 632 in leg 626 is a liner with opening 710. Contacting element632 from leg 624 passes through opening 710. Contactor 640 is coupled tothe end of contacting element 632 from leg 624. Contactor 640 provideselectrical coupling between contacting elements in legs 624 and 626.

In certain embodiments, contacting elements 632 include one or more finsor projections. The fins or projections may increase an electricalcontact area of contacting elements 632. In some embodiments, contactingelement 632 of leg 626 has an opening or other orifice that allows thecontacting element of 624 to couple to the contacting element of leg626.

In certain embodiments, legs 624 and 626 are coupled together to form adiad. Three diads may be coupled to a three-phase transformer to powerthe legs of the heaters. FIG. 92 depicts an embodiment of three diadscoupled to a three-phase transformer. In certain embodiments,transformer 634 is a delta three-phase transformer. Diad 712A includeslegs 624A and 626A. Diad 712B includes legs 624B and 626B. Diad 712Cincludes legs 624C and 626C. Diads 712A, 712B, 712C are coupled to thesecondaries of transformer 634. Diad 712A is coupled to the “A”secondary. Diad 712B is coupled to the “B” secondary. Diad 712C iscoupled to the “C” secondary.

Coupling the diads to the secondaries of the delta three-phasetransformer isolates the diads from ground. Isolating the diads fromground inhibits leakage to the formation from the diads. Coupling thediads to different phases of the delta three-phase transformer alsoinhibits leakage between the heating legs of the diads in the formation.

In some embodiments, diads are used for treating formations usingtriangular or hexagonal heater patterns. FIG. 93 depicts an embodimentof groups of diads in a hexagonal pattern. Heaters may be placed at thevertices of each of the hexagons in the hexagonal pattern. Each group714 of diads (enclosed by dashed circles) may be coupled to a separatethree-phase transformer. “A”, “B”, and “C” inside groups 714 representeach diad (for example, diads 712A, 712B, 712C depicted in FIG. 92) thatis coupled to each of the three secondary phases of the transformer witheach phase coupled to one diad (with the heaters at the vertices of thehexagon). The numbers “1”, “2”, and “3” inside the hexagons representthe three repeating types of hexagons in the pattern depicted in FIG.93.

FIG. 94 depicts an embodiment of diads in a triangular pattern. Threediads 712A, 712B, 712C may be enclosed in each group 714 of diads(enclosed by dashed rectangles). Each group 714 may be coupled to aseparate three-phase transformer.

In certain embodiments, exposed metal heating elements are used insubstantially horizontal sections of u-shaped wellbores. Substantiallyu-shaped wellbores may be used in tar sands formations, oil shaleformation, or other formations with relatively thin hydrocarbon layers.Tar sands or thin oil shale formations may have thin shallow layers thatare more easily and uniformly heated using heaters placed insubstantially u-shaped wellbores. Substantially u-shaped wellbores mayalso be used to process formations with thick hydrocarbon layers informations. In some embodiments, substantially u-shaped wellbores areused to access rich layers in a thick hydrocarbon formation.

Heaters in substantially u-shaped wellbores may have long lengthscompared to heaters in vertical wellbores because horizontal heatingsections do not have problems with creep or hanging stress encounteredwith vertical heating elements. Substantially u-shaped wellbores maymake use of natural seals in the formation and/or the limited thicknessof the hydrocarbon layer. For example, the wellbores may be placed aboveor below natural seals in the formation without punching large numbersof holes in the natural seals, as would be needed with verticallyoriented wellbores. Using substantially u-shaped wellbores instead ofvertical wellbores may also reduce the number of wells needed to treat asurface footprint of the formation. Using less wells reduces capitalcosts for equipment and reduces the environmental impact of treating theformation by reducing the amount of wellbores on the surface and theamount of equipment on the surface. Substantially u-shaped wellbores mayalso utilize a lower ratio of overburden section to heated section thanvertical wellbores.

Substantially u-shaped wellbores may allow for flexible placement ofopening of the wellbores on the surface. Openings to the wellbores maybe placed according to the surface topology of the formation. In certainembodiments, the openings of wellbores are placed at geographicallyaccessible locations such as topological highs (for examples, hills).For example, the wellbore may have a first opening on a first topologichigh and a second opening on a second topologic high and the wellborecrosses beneath a topologic low (for example, a valley with alluvialfill) between the first and second topologic highs. This placement ofthe openings may avoid placing openings or equipment in topologic lowsor other inaccessible locations. In addition, the water level may not beartesian in topologically high areas. Wellbores may be drilled so thatthe openings are not located near environmentally sensitive areas suchas, but not limited to, streams, nesting areas, or animal refuges.

FIG. 95 depicts a side-view representation of an embodiment of a heaterwith an exposed metal heating element placed in a substantially u-shapedwellbore. Heaters 716A, 716B, 716C have first end portions at firstlocation 646 on surface 534 of the formation and second end portions atsecond location 650 on the surface. Heaters 716A, 716B, 716C havesections 718 in overburden 458. Sections 718 are configured to providelittle or no heat output. In certain embodiments, sections 718 includean insulated electrical conductor such as insulated copper. Sections 718are coupled to heating elements 630.

In certain embodiments, portions of heating elements 630 aresubstantially parallel in hydrocarbon layer 460. In certain embodiments,heating elements 630 are exposed metal heating elements. In certainembodiments, heating elements 630 are exposed metal temperature limitedheating elements. Heating elements 630 may include ferromagneticmaterials such as 9% by weight to 13% by weight chromium stainless steellike 410 stainless steel, chromium stainless steels such as T/P91 orT/P92, 409 stainless steel, VM12 (Vallourec and Mannesmann Tubes,France) or iron-cobalt alloys for use as temperature limited heaters. Insome embodiments, heating elements 630 are composite temperature limitedheating elements such as 410 stainless steel and copper compositeheating elements or 347H, iron, copper composite heating elements.Heating elements 630 may have lengths of at least about 100 m, at leastabout 500 m, or at least about 1000 m, up to lengths of about 6000 m.

Heating elements 630 may be solid rods or tubulars. In certainembodiments, solid rod heating elements have diameters several times theskin depth at the Curie temperature of the ferromagnetic material.Typically, the solid rod heating elements may have diameters of 1.91 cmor larger (for example, 2.5 cm, 3.2 cm, 3.81 cm, or 5.1 cm). In certainembodiments, tubular heating elements have wall thicknesses of at leasttwice the skin depth at the Curie temperature of the ferromagneticmaterial. Typically, the tubular heating elements have outside diametersof between about 2.5 cm and about 15.2 cm and wall thickness in rangebetween about 0.13 cm and about 1.01 cm.

In certain embodiments, tubular heating elements 630 allow fluids to beconvected through the tubular heating elements. Fluid flowing throughthe tubular heating elements may be used to preheat the tubular heatingelements, to initially heat the formation, and/or to recover heat fromthe formation after heating is completed for the in situ heat treatmentprocess. Fluids that may flow through the tubular heating elementsinclude, but are not limited to, air, water, steam, helium, carbondioxide or other fluids. In some embodiments, a hot fluid, such ascarbon dioxide or helium, flows through the tubular heating elements toprovide heat to the formation. The hot fluid may be used to provide heatto the formation before electrical heating is used to provide heat tothe formation. In some embodiments, the hot fluid is used to provideheat in addition to electrical heating. Using the hot fluid to provideheat to the formation in addition to providing electrical heating may beless expensive than using electrical heating alone to provide heat tothe formation. In some embodiments, water and/or steam flows through thetubular heating element to recover heat from the formation. The heatedwater and/or steam may be used for solution mining and/or otherprocesses.

Transition sections 720 may couple heating elements 630 to sections 718.In certain embodiments, transition sections 720 include material thathas a high electrical conductivity but is corrosion resistant, such as347 stainless steel over copper. In an embodiment, transition sectionsinclude a composite of stainless steel clad over copper. Transitionsections 720 inhibit overheating of copper and/or insulation in sections718.

FIG. 96 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 95. Heaters 716A-L may bearranged in a repeating triangular pattern on the surface of theformation, as shown in FIG. 96. A triangle may be formed by heaters716A, 716B, and 716C and a triangle formed by heaters 716C, 716D, and716E. In some embodiments, heaters 716A-L are arranged in a straightline on the surface of the formation. Heaters 716A-L have first endportions at first location 646 on the surface and second end portions atsecond location 650 on the surface. Heaters 716A-L are arranged suchthat (a) the patterns at first location 646 and second location 650correspond to each other, (b) the spacing between heaters is maintainedat the two locations on the surface, and/or (c) the heaters all havesubstantially the same length (substantially the same horizontaldistance between the end portions of the heaters on the surface as shownin the top view of FIG. 96).

As depicted in FIGS. 95 and 96, cables 722, 724 may be coupled totransformer 728 and one or more heater units, such as the heater unitincluding heaters 716A, 716B, 716C. Cables 722, 724 may carry a largeamount of power. In certain embodiments, cables 722, 724 are capable ofcarrying high currents with low losses. For example, cables 722, 724 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 722 and/or cable 724 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and reduce the size of the cables needed to coupletransformer 728 to the heaters. In some embodiments, cables 722, 724 maybe made of carbon nanotubes. Carbon nanotubes as conductors may haveabout 1000 times the conductivity of copper for the same diameter. Also,carbon nanotubes may not require refrigeration during use.

In certain embodiments, bus bar 726A is coupled to first end portions ofheaters 716A-L and bus bar 726B is coupled to second end portions ofheaters 716A-L. Bus bars 726A,B electrically couple heaters 716A-L tocables 722, 724 and transformer 728. Bus bars 726A,B distribute power toheaters 716A-L. In certain embodiments, bus bars 726A,B are capable ofcarrying high currents with low losses. In some embodiments, bus bars726A,B are made of superconducting material such as the superconductormaterial used in cables 722, 724. In some embodiments, bus bars 726A,Bmay include carbon nanotube conductors.

As shown in FIGS. 95 and 96, heaters 716A-L are coupled to a singletransformer 728. In certain embodiments, transformer 728 is a source oftime-varying current. In certain embodiments, transformer 728 is anelectrically isolated, single-phase transformer. In certain embodiments,transformer 728 provides power to heaters 716A-L from an isolatedsecondary phase of the transformer. First end portions of heaters 716A-Lmay be coupled to one side of transformer 728 while second end portionsof the heaters are coupled to the opposite side of the transformer.Transformer 728 provides a substantially common voltage to the first endportions of heaters 716A-L and a substantially common voltage to thesecond end portions of heaters 716A-L. In certain embodiments,transformer 728 applies a voltage potential to the first end portions ofheaters 716A-L that is opposite in polarity and substantially equal inmagnitude to a voltage potential applied to the second end portions ofthe heaters. For example, a +660 V potential may be applied to the firstend portions of heaters 716A-L and a −660 V potential applied to thesecond end portions of the heaters at a selected point on the wave oftime-varying current (such as AC or modulated DC). Thus, the voltages atthe two end portion of the heaters may be equal in magnitude andopposite in polarity with an average voltage that is substantially atground potential.

Applying the same voltage potentials to the end portions of all heaters716A-L produces voltage potentials along the lengths of the heaters thatare substantially the same along the lengths of the heaters. FIG. 97depicts a cross-sectional representation, along a vertical plane, suchas the plane A-A shown in FIG. 95, of substantially u-shaped heaters ina hydrocarbon layer. The voltage potential at the cross-sectional pointshown in FIG. 97 along the length of heater 716A is substantially thesame as the voltage potential at the corresponding cross-sectionalpoints on heaters 716A-L shown in FIG. 97. At lines equidistant betweenheater wellheads, the voltage potential is approximately zero. Otherwells, such as production wells or monitoring wells, may be locatedalong these zero voltage potential lines, if desired. Production wells206 located close to the overburden may be used to transport formationfluid that is initially in a vapor phase to the surface. Productionwells located close to a bottom of the heated portion of the formationmay be used to transport formation fluid that is initially in a liquidphase to the surface.

In certain embodiments, the voltage potential at the midpoint of heaters716A-L is about zero. Having similar voltage potentials along thelengths of heaters 716A-L inhibits current leakage between the heaters.Thus, there is little or no current flow in the formation and theheaters may have long lengths as described above. Having the oppositepolarity and substantially equal voltage potentials at the end portionsof the heaters also halves the voltage applied at either end portion ofthe heater versus having one end portion of the heater grounded and oneend portion at full potential. Reducing (halving) the voltage potentialapplied to an end portion of the heater generally reduces currentleakage, reduces insulator requirements, and/or reduces arcing distancesbecause of the lower voltage potential to ground applied at the endportions of the heaters.

In certain embodiments, substantially vertical heaters are used toprovide heat to the formation. Opposite polarity and substantially equalvoltage potentials, as described above, may be applied to the endportions of the substantially vertical heaters. FIG. 98 depicts aside-view representation of substantially vertical heaters coupled to asubstantially horizontal wellbore. Heaters 716A, 716B, 716C, 716D, 716E,716F are located substantially vertical in hydrocarbon layer 460. Firstend portions of heaters 716A, 716B, 716C, 716D, 716E, 716F are coupledto bus bar 726A on a surface of the formation. Second end portions ofheaters 716A, 716B, 716C, 716D, 716E, 716F are coupled to bus bar 726Bin contacting section 642.

Bus bar 726B may be a bus bar located in a substantially horizontalwellbore in contacting section 642. Second end portions of heaters 716A,716B, 716C, 716D, 716E, 716F may be coupled to bus bar 726B by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to bus bar 726B (forexample, by welding or brazing the containers to the bus bar), endportions of heaters 716A, 716B, 716C, 716D, 716E, 716F are placed insidethe containers, and the thermite powder is activated to electricallycouple the heaters to the bus bar. The containers may be coupled to busbar 726B by, for example, placing the containers in holes or recesses inbus bar 726B or coupled to the outside of the bus bar and then brazingor welding the containers to the bus bar.

Bus bar 726A and bus bar 726B may be coupled to transformer 728 withcables 722, 724, as described above. Transformer 728 may providevoltages to bar 726A and bus bar 726B as described above for theembodiments depicted in FIGS. 95 and 96. For example, transformer 728may apply a voltage potential to the first end portions of heaters716A-F that is opposite in polarity and substantially equal in magnitudeto a voltage potential applied to the second end portions of theheaters. Applying the same voltage potentials to the end portions of allheaters 716A-F may produce voltage potentials along the lengths of theheaters that are substantially the same along the lengths of theheaters. Applying the same voltage potentials to the end portions of allheaters 716A-F may inhibit current leakage between the heaters and/orinto the formation. In some embodiments, heaters 716A-F are electricallycoupled in pairs to the isolated delta winding on the secondary of athree-phase transformer.

In certain embodiments, it may be advantageous to allow some currentleakage into the formation during early stages of heating to heat theformation at a faster rate. Current leakage from the heaters into theformation electrically heats the formation directly. The formation isheated by direct electrical heating in addition to conductive heatprovided by the heaters. The formation (the hydrocarbon layer) may havean initial electrical resistance that averages at least 10 ohm·m. Insome embodiments, the formation has an initial electrical resistance ofat least 100 ohm·m or of at least 300 ohm·m. Direct electrical heatingis achieved by having opposite potentials applied to adjacent heaters inthe hydrocarbon layer. Current may be allowed to leak into the formationuntil a selected temperature is reached in the heaters or in theformation. The selected temperature may be below or near the temperaturethat water proximate one or more heaters boils off. After water boilsoff, the hydrocarbon layer is substantially electrically isolated fromthe heaters and direct heating of the formation is inefficient. Afterthe selected temperature is reached, the voltage potential is applied inthe opposite polarity and substantially equal magnitude manner describedabove for FIGS. 95 and 96 so that adjacent heaters will have the samevoltage potential along their lengths.

Current is allowed to leak into the formation by reversing the polarityof one or more heaters shown in FIG. 96 so that a first group of heatershas a positive voltage potential at first location 646 and a secondgroup of heaters has a negative voltage potential at the first location.The first end portions, at first location 646, of a first group ofheaters (for example, heaters 716A, 716B, 716D, 716E, 716G, 716H, 716J,716K, depicted in FIG. 96) are applied with a positive voltage potentialthat is substantially equal in magnitude to a negative voltage potentialapplied to the second end portions, at second location 650, of the firstgroup of heaters. The first end portions, at first location 646, of thesecond group of heaters (for example, heaters 716C, 716F, 7161, 716L)are applied with a negative voltage potential that is substantiallyequal in magnitude to the positive voltage potential applied to thefirst end portions of the first group of heaters. Similarly, the secondend portions, at second location 650, of the second group of heaters areapplied with a positive voltage potential substantially equal inmagnitude to the negative potential applied to the second end portionsof the first group of heaters. After the selected temperature isreached, the first end portions of both groups of heaters are appliedwith voltage potential that is opposite in polarity and substantiallysimilar in magnitude to the voltage potential applied to the second endportions of both groups of heaters.

In some embodiments, the heating elements have a thin electricallyinsulating layer, described above, to inhibit current leakage from theheating elements. In some embodiments, the thin electrically insulatinglayer is aluminum oxide or thermal spray coated aluminum oxide. In someembodiments, the thin electrically insulating layer is an enamel coatingof a ceramic composition. The thin electrically insulating layer mayinhibit heating elements of a three-phase heater from leaking currentbetween the elements, from leaking current into the formation, and fromleaking current to other heaters in the formation. Thus, the three-phaseheater may have a longer heater length.

In certain embodiments, a plurality of substantially horizontal (orinclined) heaters are coupled to a single substantially horizontal busbar in the subsurface formation. Having the plurality of substantiallyhorizontal heaters connected to a single bus bar in the subsurfacereduces the overall footprint of heaters on the surface of the formationand the number of wells drilled in the formation. The number and spacingof heaters coupled to the single bus bar may be varied depending onfactors such as, but not limited to, size of the treatment area,vertical thickness of the formation, heating requirements for theformation, and number of layers in the formation.

FIG. 99 depicts an embodiment of pluralities of substantially horizontalheaters 716A,B coupled to bus bars 726A,B in hydrocarbon layer 460.Heaters 716A,B have sections 718 in the overburden of hydrocarbon layer460. Sections 718 may include high electrical conductivity, low thermalloss electrical conductors such as copper. Heaters 716A,B enterhydrocarbon layer 460 with substantially vertical sections and thenredirect so that the heaters have substantially horizontal sections inthe hydrocarbon layer 460. The substantially horizontal sections of716A,B in hydrocarbon layer 460 may provide the majority of the heat tothe hydrocarbon layer. Heaters 716A,B may be coupled to bus bars 726A,B,which are located distant from each other in the formation while beingsubstantially parallel to each other.

In certain embodiments, heaters 716A,B include exposed metal heatingelements. In certain embodiments, heaters 716A,B include exposed metaltemperature limited heating elements. The heating elements may includeferromagnetic materials such as 9% by weight to 13% by weight chromiumstainless steel like 410 stainless steel, chromium stainless steels suchas T/P91 or T/P92, 409 stainless steel, VM12 (Vallourec and MannesmannTubes, France) or iron-cobalt alloys for use as temperature limitedheaters. In some embodiments, the heating elements are compositetemperature limited heating elements such as 410 stainless steel andcopper composite heating elements or 347H, iron, copper compositeheating elements. The substantially horizontal sections of heaters716A,B in hydrocarbon layer 460 may have lengths of at least about 100m, at least about 500 m, or at least about 1000 m, up to lengths ofabout 6000 m.

In some embodiments, as shown in FIG. 99, two groups of heaters 716A,Benter the subsurface near each other and then branch away from eachother in hydrocarbon layer 460. Having the surface portions of more thanone group of heaters located near each other creates less of a surfacefootprint of the heaters and allows a single group of surface facilitiesto be used for both groups of heaters.

In certain embodiments, the groups of heaters 716A or 716B are eachcoupled to a single transformer. In some embodiments, three heaters inthe groups are coupled in a triad configuration (each heater is coupledto one of the phases (A, B, or C) of a three phase transformer and thebus bar is coupled to the neutral, or center point, of the transformer).Each phase of the three-phase transformer may be coupled to more thanone heater in each group of heaters (for example, phase A may be coupledto 5 heaters in the group of heaters 716A). In some embodiments, theheaters are coupled to a single phase transformer (either in series orin parallel configurations).

FIG. 100 depicts an alternative embodiment of pluralities ofsubstantially horizontal heaters 716A,B coupled to bus bars 726A,B inhydrocarbon layer 460. In such an embodiment, two groups of heaters716A,B enter the formation at distal locations on the surface of theformation. Heaters 716A,B branch towards each other in hydrocarbon layer460 so that the ends of the heaters are directed towards each other.Heaters 716A,B may be coupled to bus bars 726A,B, which are locatedproximate each other and substantially parallel to each other. Bus bars726A,B may enter the subsurface in proximity to each other so that thefootprint of the bus bars on the surface is small.

In certain embodiments, heaters 716A,B, depicted in FIG. 100, arecoupled to a single phase transformer in series or parallel. The heatersmay be coupled so that the polarity (direction of current flow)alternates in the row of heaters so that each heater has a polarityopposite the heater adjacent to it. Additionally, heaters 716A,B and busbars 726A,B may be electrically coupled such that the bus bars areopposite in polarity from each other (the current flows in oppositedirections at any point in time in each bus bar). Coupling the heatersand the bus bars in such manner inhibits current leakage into and/orthrough the formation.

As shown in FIGS. 99 and 100, heaters 716A may be electrically coupledto bus bar 726A and heaters 716B may be electrically coupled to bus bar726B. Bus bars 726A,B may electrically couple to the ends of heaters716A,B and be a return or neutral connection for the heaters with busbar 726A being the neutral connection for heaters 716A and bus bar 726Bbeing the neutral connection for heaters 716B. Bus bars 726A,B may belocated in wellbores that are formed substantially perpendicular to thepath of wellbores with heaters 716A,B, as shown in FIG. 99. Directionaldrilling and/or magnetic steering may be used so that the wells for busbars 726A,B and the wellbores for heaters 716A,B intersect.

In certain embodiments, heaters 716A,B are coupled to bus bars 726A,Busing “mousetrap” type connectors 2028. In some embodiments, othercouplings, such as those described herein or known in the art, are usedto couple heaters 716A,B to bus bars 726A,B. For example, a molten metalor a liquid conducting fluid may fill up the connection space (in thewellbores) to electrically couple the heaters and the bus bars.

FIG. 101 depicts an enlarged view of an embodiment of bus bar 726coupled to heater 716 with connectors 2028. In certain embodiments, busbar 726 includes carbon steel or other electrically conducting metals.In some embodiments, a high electrical conductivity conductor or metalis coupled to or included in bus bar 726. For example, bus bar 726 mayinclude carbon steel with copper cladded to the carbon steel.

In some embodiments, a centralizer or other centralizing device is usedto locate or guide heaters 716 and/or bus bars 726 so that the heatersand bus bars can be coupled. FIG. 102 depicts an enlarged view of anembodiment of bus bar 726 coupled to heater 716 with connectors 2028 andcentralizers 524. Centralizers 524 may locate heater 716 and/or bus bar726 so that connectors 2028 easily couple the heater and the bus bar.Centralizers 524 may ensure proper spacing of heater 716 and/or bus bar726 so that the heater and the bus bar can be coupled with connectors2028. Centralizers 524 may inhibit heater 716 and/or bus bar 726 fromcontacting the sides of the wellbores at or near connectors 2028.

FIG. 103 depicts a cross-sectional representation of connector 2028coupling to bus bar 726. FIG. 104 depicts a three-dimensionalrepresentation of connector 2028 coupling to bus bar 726. Connectors2028 are shown in proximity to bus bar 726 (before the connector clampsaround the bus bar). Connectors 2028 are connected or directly attachedto the heater so that the connector is rotatable around the end of theheater while maintaining electrical contact with the heater. Connectors2028 include collets 2030. Collets 2030 are shaped (for example,diagonally cut or helically profiled) so that as the connector is pushedonto bus bar 726, the shape of the collets rotates the head of theconnector as the collets slide over the bus bar. Collets 2030 may bespring loaded so that the collets hold down against bus bar 726 afterthe collets slide over the bus bar. Thus, connector 2028 clamps to busbar 726 using collets 2030. Connectors 2028, including collets 2030, ismade of electrically conductive materials so that the connectorelectrically couples bus bar 726 to the heater attached to theconnector.

In certain embodiments, a heater is electrically isolated from theformation because the heater has little or no voltage potential on theoutside of the heater. FIG. 105 depicts an embodiment of a substantiallyu-shaped heater that electrically isolates itself from the formation.Heater 716 has a first end portion at a first opening on surface 534 anda second end portion at a second opening on the surface. In someembodiments, heater 716 has only the first end portion at the surfacewith the second end of the heater located in hydrocarbon layer 460 (theheater is a single-ended heater). FIGS. 106 and 107 depict embodimentsof single-ended heaters that electrically isolate themselves from theformation. In certain embodiments, single-ended heater 716 has anelongated portion that is substantially horizontal in hydrocarbon layer460, as shown in FIGS. 106 and 107. In some embodiments, single-endedheater 716 has an elongated portion with an orientation other thansubstantially horizontal in hydrocarbon layer 460. For example, thesingle-ended heater may have an elongated portion that is oriented 15°off horizontal in the hydrocarbon layer.

As shown in FIGS. 105-107, heater 716 includes heating element 630located in hydrocarbon layer 460. Heating element 630 may be aferromagnetic conduit heating element or ferromagnetic tubular heatingelement. In certain embodiments, heating element 630 is a temperaturelimited heater tubular heating element. In certain embodiments, heatingelement 630 is a 9% by weight to 13% by weight chromium stainless steeltubular such as a 410 stainless steel tubular, a T/P91 stainless steeltubular, or a T/P92 stainless steel tubular. In certain embodiments,heating element 630 includes ferromagnetic material with a wallthickness of at least about one skin depth of the ferromagnetic materialat 25° C. In some embodiments, heating element 630 includesferromagnetic material with a wall thickness of at least about two timesthe skin depth of the ferromagnetic material at 25° C., at least aboutthree times the skin depth of the ferromagnetic material at 25° C., orat least about four times the skin depth of the ferromagnetic materialat 25° C.

Heating element 630 is coupled to one or more sections 718. Sections 718are located in overburden 458. Sections 718 include higher electricalconductivity materials such as copper or aluminum. In certainembodiments, sections 718 are copper clad inside carbon steel.

Center conductor 730 is positioned inside heating element 630. In someembodiments, heating element 630 and center conductor 730 are placed orinstalled in the formation by unspooling the heating element and thecenter conductor from one or more spools while they are placed into theformation. In some embodiments, heating element 630 and center conductor730 are coupled together on a single spool and unspooled as a singlesystem with the center conductor inside the heating element. In someembodiments, heating element 630 and center conductor 730 are located onseparate spools and the center conductor is positioned inside theheating element after the heating element is placed in the formation.

In certain embodiments, center conductor 730 is located at or near acenter of heating element 630. Center conductor 730 may be substantiallyelectrically isolated from heating element 630 along a length of thecenter conductor (for example, the length of the center conductor inhydrocarbon layer 460). In certain embodiments, center conductor 730 isseparated from heating element 630 by one or moreelectrically-insulating centralizers. The centralizers may includesilicon nitride or another electrically insulating material. Thecentralizers may inhibit electrical contact between center conductor 730and heating element 630 so that, for example, arcing or shorting betweenthe center conductor and the heating element is inhibited. In someembodiments, center conductor 730 is a conductor (for example, a solidconductor or a tubular conductor) so that the heater is in aconductor-in-conduit configuration.

In certain embodiments, center conductor 730 is a copper rod or coppertubular. In some embodiments, center conductor 730 and/or heatingelement 630 has a thin electrically insulating layer to inhibit currentleakage from the heating elements. In some embodiments, the thinelectrically insulating layer is aluminum oxide or thermal spray coatedaluminum oxide. In some embodiments, the thin electrically insulatinglayer is an enamel coating of a ceramic composition. The thinelectrically insulating layer may inhibit heating elements of athree-phase heater from leaking current between the elements, fromleaking current into the formation, and from leaking current to otherheaters in the formation. Thus, the three-phase heater may have a longerheater length.

In certain embodiments, center conductor 730 is an insulated conductor.The insulated conductor may include an electrically conductive coreinside an electrically conductive sheath with electrical insulationbetween the core and the sheath. In certain embodiments, the insulatedconductor includes a copper core inside a non-ferromagnetic stainlesssteel (for example, 347 stainless steel) sheath with magnesium oxideinsulation between the core and the sheath. The core may be used toconduct electrical current through the insulated conductor. In someembodiments, the insulated conductor is placed inside heating element630 without centralizers or spacers between the insulated conductor andthe heating element. The sheath and the electrical insulation of theinsulated conductor may electrically insulate the core from heatingelement 630 if the center conductor and the heating element touch. Thus,the core and heating element 630 are inhibit from electrically shortingto each other. The insulated conductor or another solid center conductor730 may be inhibited from being crushed or deformed by heating element630. In certain embodiments, one end portion of center conductor 730 iselectrically coupled to one end portion of heating element 630 atsurface 534 using electrical coupling 732, as shown in FIG. 105. In someembodiments, the end of center conductor 730 is electrically coupled tothe end of heating element 630 in hydrocarbon layer 460 using electricalcoupling 732, as shown in FIGS. 106 and 107. Thus, center conductor 730is electrically coupled to heating element 630 in a series configurationin the embodiments depicted in FIGS. 105-107. In certain embodiments,center conductor 730 is the insulated conductor and the core of theinsulated conductor is electrically coupled to heating element 630 inthe series configuration. Center conductor 730 is a return electricalconductor for heating element 630 so that current in the centerconductor flows in an opposite direction from current in the heatingelement (as represented by arrows 734). The electromagnetic fieldgenerated by current flow in center conductor 730 substantially confinesthe flow of electrons and heat generation to the inside of heatingelement 630 (for example, the inside wall of the heating element) belowthe Curie temperature and/or the phase transformation temperature rangeof the ferromagnetic material in the heating element. Thus, the outsideof heating element 630 is at substantially zero potential and theheating element is electrically isolated from the formation and anyadjacent heater or heating element at temperatures below the Curietemperature and/or the phase transformation temperature range of theferromagnetic material (for example, at 25° C.). Having the outside ofheating element 630 at substantially zero potential and the heatingelement electrically isolated from the formation and any adjacent heateror heating element allows for long length heaters to be used inhydrocarbon layer 460 without significant electrical (current) losses tothe hydrocarbon layer. For example, heaters with lengths of at leastabout 100 m, at least about 500 m, or at least about 1000 m may be usedin hydrocarbon layer 460.

During application of electrical current to heating element 630 andcenter conductor 730, heat is generated by the heater. In certainembodiments, heating element 630 generates a majority or all of the heatoutput of the heater. For example, when electrical current flows throughferromagnetic material in heating element 630 and copper or another lowresistivity material in center conductor 730, the heating elementgenerates a majority or all of the heat output of the heater. Generatinga majority of the heat in the outer conductor (heating element 630)instead of center conductor 730 may increase the efficiency of heattransfer to the formation by allowing direct heat transfer from the heatgenerating element (heating element 630) to the formation and may reduceheat losses across heater 716 (for example, heat losses between thecenter conductor and the outer conductor if the center conductor is theheat generating element). Generating heat in heating element 630 insteadof center conductor 730 also increases the heat generating surface areaof heater 716. Thus, for the same operating temperature of heater 716,more heat can be provided to the formation using the outer conductor(heating element 630) as the heat generating element rather than centerconductor 730.

In some embodiments, a fluid flows through heater 716 (represented byarrows 736 in FIGS. 105 and 106) to preheat the formation and/or torecover heat from the heating element. In the embodiment depicted inFIG. 105, fluid flows from one end of heater 716 to the other end of theheater inside and through heating element 630 and outside centerconductor 730, as shown by arrows 736. In the embodiment depicted inFIG. 106, fluid flows into heater 716 through center conductor 730,which is a tubular conductor, as shown by arrows 736. Center conductor730 includes openings 738 at the end of the center conductor to allowfluid to exit the center conductor. Openings 738 may be perforations orother orifices that allow fluid to flow into and/or out of centerconductor 730. Fluid then returns to the surface inside heating element630 and outside center conductor 730, as shown by arrows 736.

Fluid flowing inside heater 716 (represented by arrows 736 in FIGS. 105and 106) may be used to preheat the heater, to initially heat theformation, and/or to recover heat from the formation after heating iscompleted for the in situ heat treatment process. Fluids that may flowthrough the heater include, but are not limited to, air, water, steam,helium, carbon dioxide or other high heat capacity fluids. In someembodiments, a hot fluid, such as carbon dioxide, helium, or DOWTHERM®(The Dow Chemical Company, Midland, Mich., U.S.A.), flows through thetubular heating elements to provide heat to the formation. The hot fluidmay be used to provide heat to the formation before electrical heatingis used to provide heat to the formation. In some embodiments, the hotfluid is used to provide heat in addition to electrical heating. Usingthe hot fluid to provide heat to or preheat the formation in addition toproviding electrical heating may be less expensive than using electricalheating alone to provide heat to the formation. In some embodiments,water and/or steam flows through the tubular heating element to recoverheat from the formation after in situ heat treatment of the formation.The heated water and/or steam may be used for solution mining and/orother processes.

In some embodiments, an insulated conductor heater is placed in theformation by itself and the outside of the insulated conductor heater iselectrically isolated from the formation because the heater has littleor no voltage potential on the outside of the heater. FIG. 108 depictsan embodiment of a single-ended, substantially horizontal insulatedconductor heater that electrically isolates itself from the formation.In such an embodiment, heater 716 is insulated conductor 558. Insulatedconductor 558 may be a mineral insulated conductor heater (for example,insulated conductor 558 depicted in FIGS. 109A and 109B). Insulatedconductor 558 is located in opening 522 in hydrocarbon layer 460. Incertain embodiments, opening 522 is an uncased or open wellbore. In someembodiments, opening 522 is a cased or lined wellbore. In someembodiments, insulated conductor heater 558 is a substantially u-shapedheater and is located in a substantially u-shaped opening (for example,the opening depicted in FIG. 105).

Insulated conductor 558 has little or no current flowing along theoutside surface of the insulated conductor so that the insulatedconductor is electrically isolated from the formation and leaks littleor no current into the formation. The outside surface (or jacket) ofinsulated conductor 558 is a metal or thermal radiating body so thatheat is radiated from the insulated conductor to the formation.

FIGS. 109A and 109B depict cross-sectional representations of anembodiment of insulated conductor 558 that is electrically isolated onthe outside of jacket 506. In certain embodiments, jacket 506 is made offerromagnetic materials. In one embodiment, jacket 506 is made of 410stainless steel. In other embodiments, jacket 506 is made of T/P91 orT/P92 stainless steel. Core 508 is made of a highly conductive materialsuch as copper. Electrical insulator 500 is an electrically insulatingmaterial such as magnesium oxide. Insulated conductor 558 may be aninexpensive and easy to manufacture heater.

In the embodiment depicted in FIGS. 109A and 109B, core 508 bringscurrent into the formation, as shown by the arrow. Core 508 and jacket506 are electrically coupled at the distal end (bottom) of the heater.Current returns to the surface of the formation through jacket 506. Theferromagnetic properties of jacket 506 confine the current to the skindepth along the inside diameter of the jacket, as shown by arrows 736 inFIG. 109A. Jacket 506 has a thickness at least 2 or 3 times the skindepth of the ferromagnetic material used in the jacket so that most ofthe current is confined to the inside surface of the jacket and littleor no current flows on the outside diameter of the jacket. Thus, thereis little or no voltage potential on the outside of jacket 506. Havinglittle or no voltage potential on the outside surface of insulatedconductor 558 does not expose the formation to any high voltages,inhibits current leakage to the formation, and reduces or eliminates theneed for isolation transformers, which decrease energy efficiency.

Because core 508 is made of a highly conductive material such as copperand jacket 506 is made of more resistive ferromagnetic material, amajority of the heat generated by insulated conductor 558 is generatedin the jacket. Generating the majority of the heat in jacket 506increases the efficiency of radiative heat transfer from insulatedconductor 558 to the formation over an insulated conductor (or otherheater) that uses a core or a center conductor to generate the majorityof the heat.

In certain embodiments, core 508 is made of copper. Using copper in core508 allows the heating section of the heater and the overburden sectionto have identical core materials. Thus, the heater may be made from onelong core assembly. The long single core assembly reduces or eliminatesthe need for welding joints in the core, which can be unreliable andsusceptible to failure. Additionally, the long, single core assemblyheater may be manufactured remote from the installation site andtransported in a final assembly (ready to install assembly) to theinstallation site. The single core assembly also allows for long heaterlengths (for example, about 1000 m or longer) depending on the breakdownvoltage of the electrical insulator.

In certain embodiments, jacket 506 is made from two or more layers ofthe same materials and/or different materials. Jacket 506 may be formedfrom two or more layers to achieve thicknesses needed for the jacket(for example, to have a thickness at least 3 times the skin depth of theferromagnetic material used in the jacket). Manufacturing and/ormaterial limitations may limit the thickness of a single layer of jacketmaterial. For example, the amount each layer can be strained duringmanufacturing (forming) the layer on the heater may limit the thicknessof each layer. Thus, to reach jacket thicknesses needed for certainembodiments of insulated conductor 558, jacket 506 may be formed fromseveral layers of jacket material. For example, three layers of T/P92stainless steel may be used to form jacket 506 with a thickness of about3 times the skin depth of the T/P92 stainless steel.

In some embodiments, jacket 506 includes two or more differentmaterials. In some embodiments, jacket 506 includes different materialsin different layers of the jacket. For example, jacket 506 may have oneor more inner layers of ferromagnetic material chosen for theirelectrical and/or electromagnetic properties and one or more outerlayers chosen for its non-corrosive properties.

In some embodiments, the thickness of jacket 506 and/or the material ofthe jacket are varied along the heater length. The thickness and/ormaterial of jacket 506 may be varied to vary electrical propertiesand/or mechanical properties along the length of the heater. Forexample, the thickness and/or material of jacket 506 may be varied tovary the turndown ratio along the length of the heater. In someembodiments, the inner layer of jacket 506 includes copper or otherhighly conductive metals in the overburden section of the heater. Theinner layer of copper limits heat losses in the overburden section ofthe heater.

FIGS. 110A and 110B depict an embodiment for using substantiallyu-shaped wellbores to time sequence heat two layers in a hydrocarboncontaining formation. A single heater is shown in the embodimentsdepicted in FIGS. 110A and 110B, it is to be understood, however, thatthere are typically several heaters located in a hydrocarbon layer andthat only one heater is shown in the drawings for simplicity. In FIG.11A, opening 522A is formed in hydrocarbon layer 460A extending betweenopenings 522. In certain embodiments, opening 522A is a substantiallyhorizontal opening in hydrocarbon layer 460A. In some embodiments,opening 522A is an inclined opening in hydrocarbon layer 460A (forexample, the layer may be an angled layer and the opening is angled tobe substantially horizontal in the layer). Openings 522 are openings(for example, relatively vertical openings) that extend from the surfaceinto hydrocarbon layer 460A. Hydrocarbon layer 460A may be separatedfrom hydrocarbon layer 460B by impermeable zone 740. In certainembodiments, hydrocarbon layer 460B is an upper layer or a layer at alesser depth than hydrocarbon layer 460A. In some embodiments,hydrocarbon layer 460B is a lower layer or a layer at a greater depththan hydrocarbon layer 460A. In certain embodiments, impermeable zone740 provides a substantially impermeable seal that inhibits fluid flowbetween hydrocarbon layer 460A and hydrocarbon layer 460B. In certainembodiments (for example, in an oil shale formation), hydrocarbon layer460A has a higher richness than hydrocarbon layer 460B.

As shown in FIG. 11A, heating element 630A is located in opening 522A inhydrocarbon layer 460A. Overburden casing 530 is placed along therelatively vertical walls of openings 522 in hydrocarbon layer 460B.Overburden casing 530 inhibits heat transfer to hydrocarbon layer 460Bwhile heat is provided to hydrocarbon layer 460A by heating element630A. Heating element 630A is used to provide heat to hydrocarbon layer460A. Formation fluids (such as mobilized hydrocarbons, pyrolyzedhydrocarbons, and/or water) may be produced from hydrocarbon layer 460Aduring and/or after heating of the layer by heating element 630A.

Heat may be provided to hydrocarbon layer 460A by heating element 630Afor a selected amount of time (for example, a first amount of time). Theselected amount of time may be based on a variety of factors including,but not limited to, formation characteristics or properties, present orfuture economic factors, or capital costs. For example, for an oil shaleformation, hydrocarbon layer 460A may have a richness of about 0.12 L/kg(30.5 gals/ton) and the layer is heated for about 25 years. Productionof formation fluids from hydrocarbon layer 460A may continue from thelayer until production slows down to an uneconomical rate.

After hydrocarbon layer 460A is heated for the selected amount of time,heating element 630A is turned down and/or off. After heating element630A is turned off, the heating element may be pulled firmly (forexample, yanked) upwards so that the heating element breaks off at links742. Both ends of heating element 630A at the surface may be pulledsimultaneously so that links 742 break approximately simultaneously.Links 742 may be weak links designed to pull apart when a selected orsufficient amount of pulling force is applied to the links. For example,links 742 may be breakable mechanical couplings between portions of theheating element. The upper portions of heating element 630A are thenpulled out of the formation and the substantially horizontal portion ofheating element 630A is left in opening 522A, as shown in FIG. 110B.

In some embodiments, only one link 742 may be broken so that the upperportion above the one link can be removed and the remaining portions ofthe heater can be removed by pulling on the opposite end of the heater.Thus, the entire length of heating element 630A may be removed from theformation.

After upper portions of heating element 630A are removed from openings522, plugs 744 may be placed into openings 522 at a selected location inhydrocarbon layer 460B, as depicted in FIG. 110B. In certainembodiments, plugs 744 are placed into openings 522 at or nearimpermeable zone 740. Plugs 744 may include isolation materials such assubstantially impermeable materials or other materials that inhibitfluid flow between the hydrocarbon layers in the formation in openings522 (for example, the plugs may isolate hydrocarbon layer 460A). In someembodiments, packing 532 is placed into openings 522 above plugs 744. Insome embodiments, packing 532 is placed in openings 522 without plugs inthe openings. Packing 532 may include substantially impermeablematerials or other materials to inhibit fluid flow.

After plugs 744 and/or packing 532 is set into place in openings 522,substantially horizontal opening 522B may be formed in hydrocarbon layer460B. Opening 522B may be formed by punching (for example, drilling)through casing 530 on the wall of opening 522. In certain embodiments,opening 522B is a substantially horizontal opening in hydrocarbon layer460B. In some embodiments, opening 522B is an inclined opening inhydrocarbon layer 460B (for example, the layer may be an angled layerand the opening is angled to be substantially horizontal in the layer).Heating element 630B is then placed into opening 522B. Heating element630B may be used to provide heat to hydrocarbon layer 460B. Formationfluids, such as pyrolyzed hydrocarbons and/or mobilized hydrocarbons,may be produced from hydrocarbon layer 460B during and/or after heatingof the layer by heating element 630B.

In certain embodiments, opening 522 is a single-ended horizontal openingin hydrocarbon layer 460A (for example, the opening has only one endopen at the surface of the formation). FIGS. 111A and 111B depict anembodiment for using single-ended horizontal wellbores to time sequenceheat two layers in a hydrocarbon containing formation. A single heateris shown in the embodiments depicted in FIGS. 111A and 111B, it is to beunderstood, however, that there are typically several heaters located ina hydrocarbon layer and that only one heater is shown in the drawingsfor simplicity.

In FIG. 111A, opening 522A is formed in hydrocarbon layer 460A extendingfrom opening 522. In certain embodiments, opening 522A is asubstantially horizontal opening in hydrocarbon layer 460A thatterminates in the layer. In some embodiments, opening 522A is aninclined opening in hydrocarbon layer 460A (for example, the layer maybe an angled layer and the opening is angled to be substantiallyhorizontal in the layer). Opening 522 is an opening (for example, arelatively vertical opening) that extends from the surface intohydrocarbon layer 460A. Hydrocarbon layer 460A may be separated fromhydrocarbon layer 460B by impermeable zone 740. In certain embodiments,hydrocarbon layer 460B is an upper layer or a layer at a lesser depththan hydrocarbon layer 460A. In other embodiments, hydrocarbon layer460B is a lower layer or a layer at a greater depth than hydrocarbonlayer 460A. In certain embodiments, impermeable zone 740 provides asubstantially impermeable seal that inhibits fluid flow betweenhydrocarbon layer 460A and hydrocarbon layer 460B. In certainembodiments (for example, in an oil shale formation), hydrocarbon layer460A has a higher richness than hydrocarbon layer 460B.

As shown in FIG. 111A, heating element 630A is located in opening 522Ain hydrocarbon layer 460A. Overburden casing 530 is placed along therelatively vertical walls of opening 522 in hydrocarbon layer 460B.Overburden casing 530 inhibits heat transfer to hydrocarbon layer 460Bwhile heat is provided to hydrocarbon layer 460A by heating element630A. Heating element 630A is used to provide heat to hydrocarbon layer460A. Formation fluids (such as mobilized hydrocarbons, pyrolyzedhydrocarbons, and/or water) may be produced from hydrocarbon layer 460Aduring and/or after heating of the layer by heating element 630A.

Heat may be provided to hydrocarbon layer 460A by heating element 630Afor a selected amount of time. The selected amount of time may be basedon a variety of factors including, but not limited to, formationcharacteristics or properties, present or future economic factors, orcapital costs. For example, for an oil shale formation, hydrocarbonlayer 460A may have a richness of about 0.12 L/kg (30.5 gals/ton) andthe layer is heated for about 25 years. Production of formation fluidsfrom hydrocarbon layer 460A may continue from the layer until productionslows down to an uneconomical rate.

After hydrocarbon layer 460A is heated for the selected amount of time,heating element 630A is turned down and/or off. After heating element630A is turned down and/or off, the heating element may be removed fromopening 522A. In some embodiments, one or more portions of heatingelement 630A are left in opening 522A. For example, portions ofhydrocarbon layer 460A may clamp or squeeze on heating element 630A sothat the heating element cannot be completely removed from opening 522A.In such cases, heating element 630A may be broken at link 742 and theupper portion of heating element 630A is pulled out of the formation andthe substantially horizontal portion of the heating element is left inopening 522A.

After heating element 630A is removed from opening 522, plug 744 may beplaced into opening 522 at a selected location in hydrocarbon layer460B, as depicted in FIG. 11B. In certain embodiments, plug 744 isplaced into opening 522 at or near impermeable zone 740. Plug 744 mayinclude isolation materials such as substantially impermeable materialsor other materials that inhibit fluid flow between the hydrocarbonlayers in the formation in openings 522 (for example, the plug mayisolate hydrocarbon layer 460A). In some embodiments, packing 532 isplaced into opening 522 above plug 744. In some embodiments, packing 532is placed in opening 522 without a plug in the opening. Packing 532 mayinclude substantially impermeable materials or other materials toinhibit fluid flow.

After plug 744 and/or packing 532 is set into place in opening 522,substantially horizontal opening 522B may be formed in hydrocarbon layer460B. Opening 522B may extend horizontally from opening 522. In certainembodiments, opening 522B is a substantially horizontal opening inhydrocarbon layer 460B that terminates in the layer. In someembodiments, opening 522B is an inclined opening in hydrocarbon layer460B (for example, the layer may be an angled layer and the opening isangled to be substantially horizontal in the layer). Opening 522B may beformed by punching (for example, drilling) through casing 530 on thewall of opening 522. Heating element 630B is then placed into opening522B. Heating element 630B may be used to provide heat to hydrocarbonlayer 460B. Formation fluids, such as pyrolyzed hydrocarbons and/ormobilized hydrocarbons, may be produced from hydrocarbon layer 460Bduring and/or after heating of the layer by heating element 630B.

Heating hydrocarbon layers 460A, 460B in the time-sequenced mannersdescribed above may be more economical than producing from only onelayer or using vertical heaters to provide heat to the layerssimultaneously. Using relatively vertical openings 522 to access bothhydrocarbon layers at different times may save on capital costsassociated with forming openings in the formation and providing surfacefacilities to power the heating elements. Heating hydrocarbon layer 460Afirst before heating hydrocarbon layer 460B may improve the economics oftreating the formation (for example, the net present value of a projectto treat the formation). In addition, impermeable zone 740 and packing532 may provide a seal for hydrocarbon layer 460A after heating andproduction from the layer. This seal may be useful for abandonment ofthe hydrocarbon layer after treating the hydrocarbon layer.

In some embodiments, heat may be scavenged from hydrocarbon layer 460Aand used to provide heat to hydrocarbon layer 460B. For example, a heattransfer fluid may be circulated through opening 522A to recover heatfrom hydrocarbon layer 460A. The heat transfer fluid may later be usedto provide heat directly or indirectly (for example, using a heatexchanger to transfer heat to another heating fluid) to hydrocarbonlayer 460B. In some embodiments, heat recovered from hydrocarbon layer460A is used to provide power (for example, electrical power) to otherheaters (for example, heating element 630B used in hydrocarbon layer460B).

In some embodiments, synthesis gas generation or other post-treatmentprocesses may be performed in hydrocarbon layer 460A before heating inhydrocarbon layer 460B is started. For example, carbon dioxide or othermaterials may be sequestered in hydrocarbon layer 460A before pluggingor sealing off the layer.

In certain embodiments, portions of the wellbore that extend through theoverburden include casings. The casings may include materials thatinhibit inductive effects in the casings. Inhibiting inductive effectsin the casings may inhibit induced currents in the casing and/or reduceheat losses to the overburden. In some embodiments, the overburdencasings may include non-metallic materials such as fiberglass,polyvinylchloride (PVC), chlorinated PVC (CPVC), high-densitypolyethylene (HDPE), high temperature polymers (such as nitrogen basedpolymers), or other high temperature plastics. HDPEs with workingtemperatures in a usable range include HDPEs available from Dow ChemicalCo., Inc. (Midland, Mich., U.S.A.). The overburden casings may be madeof materials that are spoolable so that the overburden casings can bespooled into the wellbore. In some embodiments, overburden casings mayinclude non-magnetic metals such as aluminum or non-magnetic alloys suchas manganese steels having at least 10% manganese, iron aluminum alloyswith at least 18% aluminum, or austentitic stainless steels such as 304stainless steel or 316 stainless steel. In some embodiments, overburdencasings may include carbon steel or other ferromagnetic material coupledon the inside diameter to a highly conductive non-ferromagnetic metal(for example, copper or aluminum) to inhibit inductive effects or skineffects. In some embodiments, overburden casings are made of inexpensivematerials that may be left in the formation (sacrificial casings).

In certain embodiments, wellheads for the wellbores may be made of oneor more non-ferromagnetic materials. FIG. 112 depicts an embodiment ofwellhead 2032. The components in the wellheads may include fiberglass,PVC, CPVC, HDPE, high temperature polymers (such as nitrogen basedpolymers), and/or non-magnetic alloys or metals. Some materials (such aspolymers) may be extruded into a mold or reaction injection molded (RIM)into the shape of the wellhead. Forming the wellhead from a mold may bea less expensive method of making the wellhead and save in capital costsfor providing wellheads to a treatment site. Using non-ferromagneticmaterials in the wellhead may inhibit undesired heating of components inthe wellhead. Ferromagnetic materials used in the wellhead may beelectrically and/or thermally insulated from other components of thewellhead. In some embodiments, an inert gas (for example, nitrogen orargon) is purged inside the wellhead and/or inside of casings to inhibitreflux of heated gases into the wellhead and/or the casings.

In some embodiments, ferromagnetic materials in the wellhead areelectrically coupled to a non-ferromagnetic material (for example,copper) to inhibit skin effect heat generation in the ferromagneticmaterials in the wellhead. The non-ferromagnetic material is inelectrical contact with the ferromagnetic material so that current flowsthrough the non-ferromagnetic material. In certain embodiments, as shownin FIG. 112, non-ferromagnetic material 2034 is coupled (andelectrically coupled) to the inside walls of conduit 518 and wellheadwalls 2036. In some embodiments, copper may be plasma sprayed, coated,clad, or lined on the inside and/or outside walls of the wellhead. Insome embodiments, a non-ferromagnetic material such as copper is welded,brazed, clad, or otherwise electrically coupled to the inside and/oroutside walls of the wellhead. For example, copper may be swaged out toline the inside walls in the wellhead. Copper may be liquid nitrogencooled and then allowed to expand to contact and swage against theinside walls of the wellhead. In some embodiments, the copper ishydraulically expanded or explosively bonded to contact against theinside walls of the wellhead.

In some embodiments, two or more substantially horizontal wellbores arebranched off of a first substantially vertical wellbore drilleddownwards from a first location on a surface of the formation. Thesubstantially horizontal wellbores may be substantially parallel througha hydrocarbon layer. The substantially horizontal wellbores mayreconnect at a second substantially vertical wellbore drilled downwardsat a second location on the surface of the formation. Having multiplewellbores branching off of a single substantially vertical wellboredrilled downwards from the surface reduces the number of openings madeat the surface of the formation.

Continuous tubulars, such as coil tubing, have been used for many years.Running continuous tubulars into and/or out of a wellbore may be simplerand faster than running tubing formed of conventional jointed pipe.

Continuous tubulars may be run into and/or out of wellbores usinginjectors. Injectors may force the continuous tubulars into the wellsthrough a lubricator assembly or stuffing box to overcome any wellpressure until the weight of the continuous tubulars exceeds the forceapplied by the well pressure that acts against the cross-sectional areaof the continuous tubulars. Once the weight of the continuous tubularovercomes the pressure, the continuous tubular may need to be supportedby the injector. The process may be reversed as the continuous tubularis removed from the well.

A method for running dual jointed tubing strings into and out of wellsis described in U.S. Pat. No. 4,474,236 to Kellett, which isincorporated by reference as if fully set forth herein. Kellettdescribes a method and apparatus for completing a well using jointedproduction and service strings of different diameters. The methodincludes steps of running the production string on a main tubing stringhanger while maintaining control with a variable bore blowout preventer;and, running the service string into the main tubing string hanger whilemaintaining control with a dual bore blowout preventer.

Continuous tubulars have been used for various well treatment processessuch as fracturing, acidizing, and gravel packing. Typically, severalthousand feet of flexible, seamless tubing is coiled onto a large reelthat is mounted on a truck or skid. A continuous tubular injector with achain-track drive, or equivalent, may be mounted above the wellhead. Thecontinuous tubular may be fed to the injector for injection into thewell. The continuous tubular may be straightened as it is removed fromthe reel by a continuous tubular guide that aligns the continuoustubular with the wellbore and the injector mechanism.

The use of dual continuous tubulars for well servicing and production isknown in the art. Recent developments in well completion and wellworkover have demonstrated the utility of using two continuous tubularsconcurrently for many downhole operations. A difficulty with injectingdual continuous tubulars into a wellbore is the proximity of therespective continuous tubulars and the lack of working space to deploy apair of continuous tubular injector assemblies mounted above thewellhead. This problem was apparently resolved with a coil tubing stringinjector assembly adapted to simultaneously inject dual string coiltubing into a wellbore, as disclosed in U.S. Pat. No. 6,516,891 toDallas, which is incorporated herein by reference.

Another problem associated with the injection of dual continuoustubulars into a wellbore is the prevention of fluid leakage during theinjection of the dual continuous tubulars, especially when a longdownhole tool is connected to one or both of the continuous tubulars.Downhole tools typically have a larger diameter than the continuoustubular and cannot be plastically deformed, which presents certaindifficulties. It is known in the art how to overcome these difficultieswhile injecting a single continuous tubular. For example, U.S. Pat. No.4,940,095 to Newman, which is incorporated herein by reference,discloses a method of inserting a well service tool connected to acoiled tubing string, which avoids the high and/or remote mounting of aheavy coiled tubing injector drive mechanism. A closed-end lubricator isused to house the tool until it is run down through a blowout preventerconnected to a top of the well. The pipe rams of the blowout preventerare closed around the tool to support it while a tubing injector ismounted to the wellhead and the coil tubing string is connected to thetool. The blowout preventer is then opened and the coil tubing stringinjector is used to run the tool into the well. However, Newman fails toaddress the use of dual string continuous tubulars.

Many subsurface wells are fitted with permanent sensors, such aspressure and temperature sensors, which require electrical power totransmit signals from the sensors to a remote point at the surface.Subsurface wells may employ subsurface equipment such as pumps orheaters, which may also require electrical power. In order to supplypower to these subsurface pieces of equipment, electric current from asource outside of the wellhead must be transferred through the wellheadto the electrically responsive device. Electrical power can be supplieddownhole by several methods. These methods include, but are not limitedto, electrical umbilical cords, rigid tubular conductors, or coiledtubing. No matter which method of power supply is employed, in order totransfer the power through the wellhead, the power supply is transferredthrough either the tubing hanger or the casing hanger.

The extreme environmental conditions inside the wellhead coupled withthe rough nature of completion operations may cause damage to devicesused to supply electrical power. Damaged equipment may potentially leadto electrical short-circuits that can present a hazard to personsworking around the wellhead. Since the majority of wellhead equipment isconstructed of conductive materials, an electrical short inside of thewellhead may charge the outer surface of the wellhead. Unprotectedpersons may be exposed to electrical shock if contact is made with thewellhead's outer surface. Continuous tubulars subjected to electricalcharge (for example, heaters) may be insulated from the wellhead of thewellbore.

Typically, a continuous tubular is inserted into a wellhead through alubricator assembly or a stuffing box because there is a pressuredifferential between the wellbore and atmosphere. The pressuredifferential may be naturally or artificially created and produce oil orgas, or a mixture thereof, from the pressurized well. Wellheadmechanisms may inhibit movement of continuous tubulars upward and out ofthe wellbore as well as inhibit downward movement into the wellbore.

In certain embodiments, a suspension mechanism is capable of suspendingdual continuous tubulars (for example, dual insulated conductorheaters). In some embodiments, the suspension mechanism includes slipsor special fittings. With slips, a radial gripping force keeps dualcontinuous tubulars suspended and inhibits downward movement. In someembodiments, the slips inhibit upward movement (for example, upwardmovement of the dual continuous tubulars). Inhibiting upward movementmay be accomplished by using a reverse slip arrangement. Conventionalwellheads and hangers may not be designed to restrain movement ofcontinuous tubulars in the upward direction. Instead, conventionalwellheads and hangers may be only designed to suspend the strings due tothe gravitational load of the continuous tubulars.

Deployment and suspension of continuous tubulars in the wellbore mayrequire a mechanism that suspends the dual continuous tubulars in thewellhead by some suitable hanging mechanism or hanger. Thehanging/suspension mechanisms may function when the dual legs of thecontinuous tubulars are deployed simultaneously. Conventionally, dualcontinuous tubulars are not deployed simultaneously. In someembodiments, a suspension mechanism is able to suspend the verticaldownward load of both the tubulars as well as inhibit the upwardmovement of the tubulars.

FIG. 113 depicts an embodiment of a dual continuous tubular suspensionmechanism 2040 for inhibiting movement of at least two continuoustubulars 484. Suspension mechanism 2040 may be formed or positionedwithin wellhead 450. Suspension mechanism 2040 may include threading cutalong at least a portion of dual continuous tubulars 484 over expandedportion 484A of the tubular. In some embodiments, the tubular is aheater. In some embodiments, expanded portion 484A includes a threadedtubular portion to which a threaded collar is coupled. Suspensionmechanism 2040 may include lower portion 2040A and upper portion 2040B.Upper portion 2040B may include at least two openings with diameterslarge enough to allow passage of the tubulars, but small enough toinhibit passage of expanded portions of the tubulars. Lower portion2040A may include lip 2040A′. Lip 2040A′ may inhibit movement of thethreaded collars in a downward direction. Lip 2040A′ restricts movementof the tubulars in a downward direction once the expanded portion of thetubulars are threaded into the collars.

The wellhead and the suspension mechanism may include one or more seals2038. Seals 2038 may inhibit wellbore fluids from migrating upwards.Seals 2038 may help maintain a desired pressure in the wellbore. Wellcap448 keeps the suspension mechanism in place and inhibits upwardmovement. Wellhead 450 may include an opening in which the suspensionmechanism is positioned. The opening may narrow to a diameter less thanthat of the suspension mechanism to inhibit downward movement of thesuspension mechanism.

FIG. 114 depicts an embodiment of dual continuous tubular suspensionmechanism 2040 for inhibiting movement of at least two continuoustubulars 484. Suspension mechanism 2040 may be formed or positionedwithin wellhead 450. Continuous tubulars 484 may include expandedportion 484A and function in a similar fashion as is described in theembodiment depicted in FIG. 113. Expanded portion 484A depicted in FIG.114, however, may be formed by welding or otherwise attaching two piecesof split cylinder to tubular 484.

FIGS. 115A-B depict embodiments of dual continuous tubular suspensionmechanisms 2040. Suspension mechanisms 2040 include slip mechanisms thatinhibit upward and downward movement of tubulars 484. The slipmechanisms may include inhibitors 2044. Inhibitors 2044 may allowmovement in a first direction while inhibiting movement in a seconddirection. The second direction may be in a direction opposite to thefirst direction. Inhibitors 2044 may include upper inhibitors 2044B andlower inhibitors 2044A. Upper inhibitors 2044B may allow movement of thetubulars in a downward direction while inhibiting movement of thetubulars in an upward direction. Lower inhibitors 2044A may allowmovement of the tubulars in an upward direction, while inhibitingmovement of the tubulars in a downward direction. Inhibitors 2044 mayinhibit movement using serrations angled such that the serrations engagea tubular when the tubular moves in a first direction, but not when thetubular moves in a second direction that is substantially opposite tothe first direction.

In some embodiments, inhibitors include coatings. The coating may impartspecific desirable properties to the inhibitor to which the coating isapplied. For example, a coating may include a temperature resistantpolymer coating.

Suspension mechanism 2040 may include lower portion 2040A and upperportion 2040B. Upper portion 2040B may include at least two openingswith diameters large enough to allow passage of the tubulars at bothends of each opening, but small enough at the proximal ends of theopenings to inhibit passage of upper inhibitors 2044B in an upwarddirection. The distal ends of the openings may be large enough to allowthe upper inhibitors to sit within the openings of the upper portion2044B of suspension mechanism 2040. Lower portion 2040A may include atleast two openings with diameters large enough to allow passage of thetubulars at both ends of the openings, but small enough at the distalend of each opening to inhibit passage of lower inhibitors 2044A in adownward direction. The proximal ends of the openings may be largeenough to allow the lower inhibitors to sit within the openings of lowerportion 2040A of suspension mechanism 2040.

Suspension mechanism 2040 may include locks 2046. In some embodiments,locks 2046 are screws, bolts, or other types of fasteners. Locks 2046inhibit movement of one or more portions of suspension mechanism 2040within wellhead 450. Wellhead 450 may include an opening in whichsuspension mechanism 2040 is positioned. The opening may narrow to adiameter less than that of suspension mechanism 2040 to inhibit downwardmovement of the suspension mechanism.

FIGS. 116-117 depict embodiments of dual continuous tubular suspensionmechanisms 2040 within wellhead 450. As detailed in FIGS. 115A-B,suspension mechanisms 2040 employs a slip mechanism using upper andlower inhibitors 2044. In FIG. 116, wellcap 448 of wellhead 450 assistsin keeping suspension mechanism 2040 in position. Lock 2046 inhibitsupward movement of the wellcap and suspension mechanism 2040. In theembodiment depicted in FIG. 116, wellcap 448 is a part of a sealassembly using seals 2038.

FIG. 117 depicts an embodiment of suspension mechanisms 2040 in wellhead450. Wellcap 448 may be sandwiched between upper portion 2040A and lowerportion 2040B of suspension mechanism 2040. Lock 2046 inhibits upwardmovement of upper portion 2040A of the suspension mechanism, and thewellcap and suspension mechanism as a whole. Locks 2046′ inhibitmovement of upper portion 2040A and lower portion 2040B of suspensionmechanism 2040 and wellcap 448 in relation to one another.

FIG. 118 depicts an embodiment of pass-through fitting 2048 used tosuspend tubulars 484. Pass-through fitting 2048 may function to suspendtubulars 484. Pass-through fitting 2048 may include commerciallyavailable products (for example, available from Swagelok Company (Solon,Ohio, USA) or VULKAN LOKRING Rohrverbindung GmbH & Co. KG (Herne,Germany)). Pass-through fitting 2048 may inhibit movement of tubulars484 in the downward direction. A second mechanism may be utilized toinhibit movement of the tubulars in the upward direction. The secondmechanism may be a reverse configuration of the pass-through fittings2048.

FIG. 119 depicts an embodiment of dual slip suspension mechanism 2040for inhibiting movement of tubulars 484 positioned in an opening ofwellhead 450. FIG. 119 depicts a two-way lock arrangement using a slipmechanism. Bottom threading has right-handed threading, and topthreading has left-handed threading. Rotation of the center nut in theclockwise direction (when viewed from top) causes the fittings to bedrawn together, tightening the slips and causing the slips to grip thetubular/rod/heater. The entire assembly can then be suspended in awellhead housing as shown. Using the two lock-screws shown in thefigure, the entire assembly can be locked into place. The twolock-screws may suspend the tubular/rod/heater and restrict downward andupward movement of the tubular/rod/heater.

FIGS. 120A-B depict embodiments of lower portion of split suspensionmechanisms 2040A and lower split inhibitor assemblies 2044A for hangingdual continuous tubulars 484. Lower inhibitor assemblies 2044A and lowerportion of suspension mechanisms 2040A may be split such that they fittogether around tubulars 484. When the assembly is positioned in awellhead the assembly may function as a compression fitting to inhibitdownward movement of the tubulars. Lower inhibitor assemblies 2044A mayinclude special non-marking dies or surfaces (for example, WC particles(tungsten carbide particles) embedded in mild steel) that function tosimultaneously hold both the tubulars. Lower inhibitor assemblies 2044Amay include a specific taper angle that sits in lower portion ofsuspension mechanisms 2040A. In this configuration, the lower inhibitorassemblies 2044A are shown to have special grit-faced non-markingsurface.

FIG. 121 depicts an embodiment of dual slip suspension mechanisms 2040for inhibiting movement of tubulars 484 with a reverse configurationrelative to the embodiment depicted in FIG. 117. Upper inhibitor 2044B,which prevents upward movement, is deployed first and locked into placewith bottom locks 2046′ and lower portion of suspension mechanism 2040A.Lower inhibitor 2044A, which hangs the weight of the pipe and inhibitsdownward movement of pipe, is deployed in reverse order and locked inplace with bottom locks 2046″ and upper portion of suspension mechanism2040B. Wellcap 448 including seals 2038 are introduced next from thetop. The suspension mechanism 2040 may be locked in position using locks2046′″. A third or middle portion 2040C of the suspension mechanismcradles both the upper and lower inhibitors while the upper portion2044B and lower portion 2044A of the suspension mechanism inhibitmovement of the inhibitors within openings in middle portion 2040C ofthe suspension mechanism.

FIG. 122 depicts an embodiment of a two-part dual slip mechanism ofsuspension mechanism 2040 for inhibiting movement of tubulars 484.Middle portion 2040C of the suspension mechanism is divided into twoportions, lower portion 2040C′ and upper portion 2040C″. The twoportions of middle portion 2040C may be coupled together using lock2046C. Lock 2046C may include threaded studs as depicted in FIG. 122.The top half of each stud 2046C may have left-handed threading and thebottom half of each stud may have right-handed threading. Each stud2046C screws into the bottom and top of upper portion 2040C″ and lowerportion 2040C′ of suspension mechanism 2040. When the stud is rotated inthe clockwise direction when viewed from the top, both upper portion2040C″ and lower portion 2040C′ approach each other. Each stud isrotated a little each time in sequence going around such that the upperportion 2040C″ and lower portion 2040C′ move towards each othergradually and substantially uniformly. The movement causes theinhibitors to tighten and grip the tubulars.

In some embodiments, the above operation is done in a ‘false wellheadhousing’ (not shown) just above the wellhead after the inhibitors aretightened together, the tubulars are lifted, until they clear thefalse-wellhead, which is then removed. The tubulars along with thesuspension mechanism are lowered into a wellhead housing and the load istransferred to the shoulder (for example, a protrusion or narrowing ofthe opening in the wellhead which inhibits movement of the suspensionmechanism beyond the protrusion). The locks 2046′″ are tightened toinhibit movement of the suspension mechanism relative to the wellhead.

FIG. 123 depicts an embodiment of two-part dual slip suspensionmechanism 2040 for inhibiting movement of tubulars 484 with separatelocks 2046. FIG. 123 depicts an embodiment with a reverse configurationof inhibitors 2044 from the configuration depicted in FIGS. 121-122. InFIG. 123, the suspension mechanism is depicted in two distinct sections.The two sections may be activated separately. Lower portion 2040A of asuspension mechanism may include lower portion 2040A′ and upper portion2040A″. Portions 2040A′ and 2040A″ function in combination whenactivated to inhibit movement of inhibitors 2044B and hence inhibitupward movement of tubulars 484. Lower portion 2040A may be activated byassembling portions 2040A′, 2040A″ and inhibitors 2044B, inserting theassembly until downward movement is inhibited by lip 2050′, and uponpositioning tubulars 484, activating lock 2046′. Activating lock 2046′may compress lower portion assembly together such that inhibitors 2044Bgrip tubulars 484. Upper portion 2040B may be activated by assemblingportion 2040B and inhibitors 2044A, inserting the assembly untildownward movement is inhibited by lip 2050″, and activating lock2046″after positioning tubulars 484. Activating lock 2046″ may compressupper portion 2040B against lip 2050″. Inhibitors 2044A may be held inposition within opening in upper portion 2040B by gravity.

FIG. 124 depicts an embodiment of dual slip suspension mechanism 2040with locking upper plate 2040B for inhibiting movement of tubulars 484.The embodiment of lower portion 2040A depicted in FIG. 124 may functionin a similar manner to upper portion 2040B of the suspension mechanismdepicted in FIG. 123. Inhibitors 2044A inhibit downward movement oftubulars 484. However, instead of including a second set of inhibitorsto inhibit upward movement as in FIG. 123, upper portion 2040B (forexample, a plate) is positioned above lower portion 2040A. Upper portion2040B locks inhibitors 2044A in place to inhibit upward movement oftubulars 484 upon activation of locks. Activating locks 2046″ couplesupper portion 2040B to lower portion 2040A.

In some embodiments, lower portion 2040A may include a tapered openingextending through it. The lower portion may include a carrier with atapered shape complementary to the tapered opening in the lower portion.The carrier may sit within the tapered opening of the lower portion.Inhibitors 2044A fit in complementary tapered openings through thecarrier. The load of the tubulars, once positioned, is transferred fromthe inhibitors to the carrier to the lower portion, and then to thewellhead. Using a lower portion with a carrier for the inhibitors may beadvantageous when the distance between tubulars is small.

FIG. 125 depicts an embodiment of segmented dual slip suspensionmechanism 2040 with locking screws 2046 for inhibiting movement oftubulars 484. FIG. 125 depicts an arrangement where inhibitors 2044 areshown in six separate segments that are individually controlled by sixlocks 2046. The profile on inhibitors 2044 are such that when all theinhibitor segments are in-place, the inhibitor segments conform exactlyto the contours of the dual tubulars and grip them tight to preventmotion in both the upward and downward directions. The weight of thetubulars is transferred by the inhibitors to a load shoulder (forexample, lip 2050) in the wellhead.

Power supplies are used to provide power to downhole power devices(downhole loads) such as, but not limited to, reservoir heaters,electric submersible pumps (ESPs), compressors, electric drills,electrical tools for construction and maintenance, diagnostic systems,sensors, or acoustic wave generators. Surface based power supplies mayhave long supply cabling (power cables) that contribute to problems suchas voltage drops and electrical losses. Thus, it may be necessary toprovide power to the downhole loads at high voltages to reduceelectrical losses. However, many downhole loads are limited by anacceptable supply voltage level to the load. Therefore, an efficienthigh-voltage energy supply may not be viable without furtherconditioning. In such cases, a system for stepping down the voltage fromthe high voltage supply cable to the low voltage load may be necessary.The system may be a transformer.

The electrical power supply for downhole loads is typically providedusing alternating voltage (AC voltage) from supply grids of 50 Hz or 60Hz frequency. The voltage of the supply grid may correspond to thevoltage of the downhole load. High supply voltages may reduce loss andvoltage drop in the supply cable and/or allow the use of supply cableswith relatively small cross sections. High supply voltages, however, maycause technically difficulties and require cost intensive isolationefforts at the load. Voltage drops, electrical losses, and supply cablecross section limits may limit the length of the supply cable and, thus,the wellbore depth or depth of the downhole load. Locating thetransformer downhole may reduce the amount of cabling needed to providepower to the downhole loads and allow deeper wellbore depths and/ordownhole load depths while minimizing voltage drops and electricallosses in the power system.

Current technical solutions for offshore-applications make use ofsea-bed mounted step-down transformers to reduce cable loss (forexample, “Converter-Fed Subsea Motor Drives”, Raad, R. O.; Henriksen,T.; Raphael, H. B.; Hadler-Jacobsen, A.; Industry Applications, IEEETransactions on Volume 32, Issue 5, September-October 1996 Page(s):1069-1079, which is incorporated by reference as if fully set forthherein). However, these sea-bed mounted transformers may not be usefulto drive downhole loads under solid ground (for example, in a subsurfacewellbore).

FIGS. 126 and 127 depict an embodiment of transformer 728 that may belocated in a subsurface wellbore. FIG. 126 depicts a top viewrepresentation of the embodiment of transformer 728 showing the windingsand core of the transformer. FIG. 127 depicts a side view representationof the embodiment of transformer 728 showing the windings, the core, andthe power leads. Transformer 728 includes primary windings 2052A andsecondary windings 2052B. Primary windings 2052A and secondary windings2052B may have different cross-sectional areas.

Core 2054 may include two half-shell core sections 2054A and 2054Baround primary windings 2052A and secondary windings 2052B. In certainembodiments, core sections 2054A and 2054B are semicircular, symmetricshells. Core sections 2054A and 2054B may be single pieces that extendthe full length of transformer 728 or the core sections may be assembledfrom multiple shell segments put together (for example, multiple piecesstrung together to make the core sections). In certain embodiments, acore section is formed by putting together the section from two halves.The two halves of the core section may be put together after thewindings, which may be pre-fabricated, are placed in the transformer.

In certain embodiments, core sections 2054A and 2054B have about thesame cross section on the circumference of transformer 728 so that thecore properly guides the magnetic flux in the transformer. Core sections2054A and 2054B may be made of several layers of core material. Certainorientations of these layers may be designed to minimize eddy currentlosses in transformer 728. In some embodiments, core sections 2054A and2054B are made of continuous ribbons and windings 2052A and 2052B arewound into the core sections.

Transformer 728 may have certain advantages over current transformerconfigurations (such as a toroid core design with the winding on theoutside of the cores). Core sections 2054A and 2054B have outer surfacesthat offer large surface areas for cooling transformer 728.Additionally, transformer 728 may be sealed so that a cooling liquid maybe continuously run across the outer surfaces of the transformer to coolthe transformer. Transformer 728 may be sealed so that cooling liquidsdo not directly contact the inside of the core and/or the windings. Incertain embodiments, transformer is sealed in an epoxy resin or otherelectrically insulating sealing material. Cooling transformer 728 allowsthe transformer to operate at higher power densities. In certainembodiments, windings 2052A and 2052B are substantially isolated fromcore sections 2054A and 2054B so that the outside surfaces oftransformer 728 may touch the walls of a wellbore without causingelectrical problems in the wellbore.

In some embodiments, the profile of the core of transformer 728 and/orthe winding window profile are made with clearances to allow foradditional cooling devices, mechanical supports, and/or electricalcontacts on the transformer. In some embodiments, transformer 728 iscoupled to one or more additional transformers in the subsurfacewellbore to increase power in the wellbore and/or phase options in thewellbore. Transformer 728 and/or the phases of the transformer may becoupled to the additional transformers, and/or the varying phases of theadditional transformers, in either series or parallel configurations asneeded to provide power to the downhole load.

FIG. 128 depicts an embodiment of transformer 728 in wellbore 756.Transformer 728 is located in the overburden section of wellbore 756.The overburden section of wellbore 756 has overburden casing 530 on thewalls of the wellbore. Overburden casing 530 electrically and thermallyinsulates the overburden from the inside of wellbore 756. Packingmaterial 532 is located at the bottom of the overburden section ofwellbore 756. Packing material 532 inhibits fluid flow between theoverburden section of wellbore 756 and the heating section of thewellbore.

Power lead 2058 may be coupled to transformer 728 and pass throughpacking material 532 to provide power to the downhole load (for example,a downhole heater). In certain embodiments, cooling fluid 2056 islocated in wellbore 756. Transformer 728 may be immersed in coolingfluid 2056. Cooling fluid 2056 may cool transformer 728 by removing heatfrom the transformer and moving the heat away from the transformer.Cooling fluid 2056 may be circulated in wellbore 756 to increase heattransfer between transformer 728 and the cooling fluid. In someembodiments, cooling fluid 2056 is circulated to a chiller or other heatexchanger to remove heat from the cooling fluid and maintain atemperature of the cooling fluid at a selected temperature. Maintainingcooling fluid 2056 at a selected temperature may provide efficient heattransfer between the cooling fluid and transformer 728 so that thetransformer is maintained at a desired operating temperature.

In certain embodiments, cooling fluid 2056 maintains a temperature oftransformer 728 below a selected temperature. The selected temperaturemay be a maximum operating temperature of the transformer. In someembodiments, the selected temperature is a maximum temperature thatallows for a selected operational efficiency of the transformer. In someembodiments, transformer 728 operates at an efficiency of at least 95%,at least 90%, at least 80%, or at least 70% when the transformeroperates below the selected temperature.

In certain embodiments, cooling fluid 2056 is water. In someembodiments, cooling fluid 2056 is another heat transfer fluid such as,but not limited to, oil, ammonia, helium, or Freon® (E. I. du Pont deNemours and Company, Wilmington, Del., U.S.A.). In some embodiments, thewellbore adjacent to the overburden functions as a heat pipe.Transformer 728 boils cooling fluid 2056. Vaporized cooling fluid 2056rises in the wellbore, condenses, and flows back to transformer 728.Vaporization of cooling fluid 2056 transfers heat to the cooling fluidand condensation of the cooling fluid allows heat to transfer to theoverburden. Transformer 728 may operate near the vaporizationtemperature of cooling fluid 2056.

In some embodiments, cooling fluid is circulated in a pipe thatsurrounds the transformer. The pipe may be in direct thermal contactwith the transformer so that heat is removed from the transformer intothe cooling fluid circulating through the pipe. In some embodiments, thetransformer includes fans, heat sinks, fins, or other devices thatassist in transferring heat away from the transformer. In someembodiments, the transformer is, or includes, a solid state transformerdevice such as an AC to DC converter.

In certain embodiments, cooling fluid 2056 is circulated using a heatpipe in wellbore 756. FIG. 129 depicts an embodiment of transformer 728in wellbore 756 with heat pipes 2060A,B. Lid 2062 is placed at the topof a reservoir of cooling fluid 2056 that surrounds transformer 728.Heated cooling fluid expands and flows up heat pipe 2060A. The heatedcooling fluid 2056 cools adjacent to the overburden and flows back tolid 2062. The cooled cooling fluid 2056 flows back into the reservoirthrough heat pipe 2060B. Heat pipes 2060A,B act to create a flow pathfor the cooling fluid so that the cooling fluid circulates aroundtransformer 728 and maintains a temperature of the transformer below theselected temperature.

Computational analysis has shown that a circulated water column wassufficient to cool a 60 Hz transformer that was 125 feet in length andgenerated 80 W/ft of heat. The transformer and the formation wereinitially at ambient temperatures. The water column was initially at anelevated temperature. The water column and transformer cooled over aperiod of about 1 to 2 hours. The transformer initially heated up (butwas still at operable temperatures) but then was cooled by the watercolumn to lower operable temperatures. The computations also showed thatthe transformer would be cooled by the water column when the transformerand the formation were initially at higher than normal temperatures.

In certain embodiments, a temperature limited heater is utilized forheavy oil applications (for example, treatment of relatively permeableformations or tar sands formations). A temperature limited heater mayprovide a relatively low Curie temperature and/or phase transformationtemperature range so that a maximum average operating temperature of theheater is less than 350° C., 300° C., 250° C., 225° C., 200° C., or 150°C. In an embodiment (for example, for a tar sands formation), a maximumtemperature of the heater is less than about 250° C. to inhibit olefingeneration and production of other cracked products. In someembodiments, a maximum temperature of the heater above about 250° C. isused to produce lighter hydrocarbon products. For example, the maximumtemperature of the heater may be at or less than about 500° C.

A heater may heat a volume of formation adjacent to a productionwellbore (a near production wellbore region) so that the temperature offluid in the production wellbore and in the volume adjacent to theproduction wellbore is less than the temperature that causes degradationof the fluid. The heat source may be located in the production wellboreor near the production wellbore. In some embodiments, the heat source isa temperature limited heater. In some embodiments, two or more heatsources may supply heat to the volume. Heat from the heat source mayreduce the viscosity of crude oil in or near the production wellbore. Insome embodiments, heat from the heat source mobilizes fluids in or nearthe production wellbore and/or enhances the radial flow of fluids to theproduction wellbore. In some embodiments, reducing the viscosity ofcrude oil allows or enhances gas lifting of heavy oil (approximately atmost 10° API gravity oil) or intermediate gravity oil (approximately 12°to 20° API gravity oil) from the production wellbore. In certainembodiments, the initial API gravity of oil in the formation is at most10°, at most 20°, at most 25°, or at most 30°. In certain embodiments,the viscosity of oil in the formation is at least 0.05 Pa·s (50 cp). Insome embodiments, the viscosity of oil in the formation is at least 0.10Pa·s (100 cp), at least 0.15 Pa·s (150 cp), or at least at least 0.20Pa·s (200 cp). Large amounts of natural gas may have to be utilized toprovide gas lift of oil with viscosities above 0.05 Pa·s. Reducing theviscosity of oil at or near the production wellbore in the formation toa viscosity of 0.05 Pa·s (50 cp), 0.03 Pa·s (30 cp), 0.02 Pa·s (20 cp),0.01 Pa·s (10 cp), or less (down to 0.001 Pa·s (1 cp) or lower) lowersthe amount of natural gas needed to lift oil from the formation. In someembodiments, reduced viscosity oil is produced by other methods such aspumping.

The rate of production of oil from the formation may be increased byraising the temperature at or near a production wellbore to reduce theviscosity of the oil in the formation in and adjacent to the productionwellbore. In certain embodiments, the rate of production of oil from theformation is increased by 2 times, 3 times, 4 times, or greater up to 20times over standard cold production, which has no external heating offormation during production. Certain formations may be more economicallyviable for enhanced oil production using the heating of the nearproduction wellbore region. Formations that have a cold production rateapproximately between 0.05 m3/(day per meter of wellbore length) and0.20 m3/(day per meter of wellbore length) may have significantimprovements in production rate using heating to reduce the viscosity inthe near production wellbore region. In some formations, productionwells up to 775 m, up to 1000 m, or up to 1500 m in length are used. Forexample, production wells between 450 m and 775 m in length are used,between 550 m and 800 m are used, or between 650 m and 900 m are used.Thus, a significant increase in production is achievable in someformations. Heating the near production wellbore region may be used informations where the cold production rate is not between 0.05 m3/(dayper meter of wellbore length) and 0.20 m3/(day per meter of wellborelength), but heating such formations may not be as economicallyfavorable. Higher cold production rates may not be significantlyincreased by heating the near wellbore region, while lower productionrates may not be increased to an economically useful value.

Using the temperature limited heater to reduce the viscosity of oil ator near the production well inhibits problems associated withnon-temperature limited heaters and heating the oil in the formation dueto hot spots. One possible problem is that non-temperature limitedheaters can cause coking of oil at or near the production well if theheater overheats the oil because the heaters are at too high atemperature. Higher temperatures in the production well may also causebrine to boil in the well, which may lead to scale formation in thewell. Non-temperature limited heaters that reach higher temperatures mayalso cause damage to other wellbore components (for example, screensused for sand control, pumps, or valves). Hot spots may be caused byportions of the formation expanding against or collapsing on the heater.In some embodiments, the heater (either the temperature limited heateror another type of non-temperature limited heater) has sections that arelower because of sagging over long heater distances. These lowersections may sit in heavy oil or bitumen that collects in lower portionsof the wellbore. At these lower sections, the heater may develop hotspots due to coking of the heavy oil or bitumen. A standardnon-temperature limited heater may overheat at these hot spots, thusproducing a non-uniform amount of heat along the length of the heater.Using the temperature limited heater may inhibit overheating of theheater at hot spots or lower sections and provide more uniform heatingalong the length of the wellbore.

In some embodiments, oil or bitumen cokes in a perforated liner orscreen in a heater/production wellbore (for example, coke may formbetween the heater and the liner or between the liner and theformation). Oil or bitumen may also coke in a toe section of a heel andtoe heater/production wellbore, as shown in and described below for FIG.145. A temperature limited heater may limit a temperature of aheater/production wellbore below a coking temperature to inhibit cokingin the well so that the wellbore does not plug up.

In certain embodiments, fluids in the relatively permeable formationcontaining heavy hydrocarbons are produced with little or nopyrolyzation of hydrocarbons in the formation. In certain embodiments,the relatively permeable formation containing heavy hydrocarbons is atar sands formation. For example, the formation may be a tar sandsformation such as the Athabasca tar sands formation in Alberta, Canadaor a carbonate formation such as the Grosmont carbonate formation inAlberta, Canada. The fluids produced from the formation are mobilizedfluids. Producing mobilized fluids may be more economical than producingpyrolyzed fluids from the tar sands formation. Producing mobilizedfluids may also increase the total amount of hydrocarbons produced fromthe tar sands formation.

FIGS. 130-133 depict side view representations of embodiments forproducing mobilized fluids from tar sands formations. In FIGS. 130-133,heaters 716 have substantially horizontal heating sections inhydrocarbon layer 460 (as shown, the heaters have heating sections thatgo into and out of the page). FIG. 130 depicts a side viewrepresentation of an embodiment for producing mobilized fluids from atar sands formation with a relatively thin hydrocarbon layer. FIG. 131depicts a side view representation of an embodiment for producingmobilized fluids from a hydrocarbon layer that is thicker than thehydrocarbon layer depicted in FIG. 130. FIG. 132 depicts a side viewrepresentation of an embodiment for producing mobilized fluids from ahydrocarbon layer that is thicker than the hydrocarbon layer depicted inFIG. 131. FIG. 133 depicts a side view representation of an embodimentfor producing mobilized fluids from a tar sands formation with ahydrocarbon layer that has a shale break.

In FIG. 130, heaters 716 are placed in an alternating triangular patternin hydrocarbon layer 460. In FIGS. 131, 132, and 133, heaters 716 areplaced in an alternating triangular pattern in hydrocarbon layer 460that repeats vertically to encompass a majority or all of thehydrocarbon layer. In FIG. 133, the alternating triangular pattern ofheaters 716 in hydrocarbon layer 460 repeats uninterrupted across shalebreak 746. In FIGS. 130-133, heaters 716 may be equidistantly spacedfrom each other. In the embodiments depicted in FIGS. 130-133, thenumber of vertical rows of heaters 716 depends on factors such as, butnot limited to, the desired spacing between the heaters, the thicknessof hydrocarbon layer 460, and/or the number and location of shale breaks746. In some embodiments, heaters 716 are arranged in other patterns.For example, heaters 716 may be arranged in patterns such as, but notlimited to, hexagonal patterns, square patterns, or rectangularpatterns.

In the embodiments depicted in FIGS. 130-133, heaters 716 provide heatthat mobilizes hydrocarbons (reduces the viscosity of the hydrocarbons)in hydrocarbon layer 460. In certain embodiments, heaters 716 provideheat that reduces the viscosity of the hydrocarbons in hydrocarbon layer460 below about 0.50 Pa·s (500 cp), below about 0.10 Pa·s (100 cp), orbelow about 0.05 Pa·s (50 cp). The spacing between heaters 716 and/orthe heat output of the heaters may be designed and/or controlled toreduce the viscosity of the hydrocarbons in hydrocarbon layer 460 todesirable values. Heat provided by heaters 716 may be controlled so thatlittle or no pyrolyzation occurs in hydrocarbon layer 460. Superpositionof heat between the heaters may create one or more drainage paths (forexample, paths for flow of fluids) between the heaters. In certainembodiments, production wells 206A and/or production wells 206B arelocated proximate heaters 716 so that heat from the heaters superimposesover the production wells. The superimposition of heat from heaters 716over production wells 206A and/or production wells 206B creates one ormore drainage paths from the heaters to the production wells. In certainembodiments, one or more of the drainage paths converge. For example,the drainage paths may converge at or near a bottommost heater and/orthe drainage paths may converge at or near production wells 206A and/orproduction wells 206B. Fluids mobilized in hydrocarbon layer 460 tend toflow towards the bottommost heaters 716, production wells 206A and/orproduction wells 206B in the hydrocarbon layer because of gravity andthe heat and pressure gradients established by the heaters and/or theproduction wells. The drainage paths and/or the converged drainage pathsallow production wells 206A and/or production wells 206B to collectmobilized fluids in hydrocarbon layer 460.

In certain embodiments, hydrocarbon layer 460 has sufficientpermeability to allow mobilized fluids to drain to production wells 206Aand/or production wells 206B. For example, hydrocarbon layer 460 mayhave a permeability of at least about 0.1 darcy, at least about 1 darcy,at least about 10 darcy, or at least about 100 darcy. In someembodiments, hydrocarbon layer 460 has a relatively large verticalpermeability to horizontal permeability ratio (Kv/Kh). For example,hydrocarbon layer 460 may have a Kv/Kh ratio between about 0.01 andabout 2, between about 0.1 and about 1, or between about 0.3 and about0.7.

In certain embodiments, fluids are produced through production wells206A located near heaters 716 in the lower portion of hydrocarbon layer460. In some embodiments, fluids are produced through production wells206B located below and approximately midway between heaters 716 in thelower portion of hydrocarbon layer 460. At least a portion of productionwells 206A and/or production wells 206B may be oriented substantiallyhorizontal in hydrocarbon layer 460 (as shown in FIGS. 130-133, theproduction wells have horizontal portions that go into and out of thepage). Production wells 206A and/or 206B may be located proximate lowerportion heaters 716 or the bottommost heaters.

In some embodiments, production wells 206A are positioned substantiallyvertically below the bottommost heaters in hydrocarbon layer 460.Production wells 206A may be located below heaters 716 at the bottomvertex of a pattern of the heaters (for example, at the bottom vertex ofthe triangular pattern of heaters depicted in FIGS. 130-133). Locatingproduction wells 206A substantially vertically below the bottommostheaters may allow for efficient collection of mobilized fluids fromhydrocarbon layer 460.

In certain embodiments, the bottommost heaters are located between about2 m and about 10 m from the bottom of hydrocarbon layer 460, betweenabout 4 m and about 8 m from the bottom of the hydrocarbon layer, orbetween about 5 m and about 7 m from the bottom of the hydrocarbonlayer. In certain embodiments, production wells 206A and/or productionwells 206B are located at a distance from the bottommost heaters 716that allows heat from the heaters to superimpose over the productionwells but at a distance from the heaters that inhibits coking at theproduction wells. Production wells 206A and/or production wells 206B maybe located a distance from the nearest heater (for example, thebottommost heater) of at most ¾ of the spacing between heaters in thepattern of heaters (for example, the triangular pattern of heatersdepicted in FIGS. 130-133). In some embodiments, production wells 206Aand/or production wells 206B are located a distance from the nearestheater of at most ⅔, at most ½, or at most ⅓ of the spacing betweenheaters in the pattern of heaters. In certain embodiments, productionwells 206A and/or production wells 206B are located between about 2 mand about 10 m from the bottommost heaters, between about 4 m and about8 m from the bottommost heaters, or between about 5 m and about 7 m fromthe bottommost heaters. Production wells 206A and/or production wells206B may be located between about 0.5 m and about 8 m from the bottom ofhydrocarbon layer 460, between about 1 m and about 5 m from the bottomof the hydrocarbon layer, or between about 2 m and about 4 m from thebottom of the hydrocarbon layer.

In some embodiments, at least some production wells 206A are locatedsubstantially vertically below heaters 716 near shale break 746, asdepicted in FIG. 133. Production wells 206A may be located betweenheaters 716 and shale break 746 to produce fluids that flow and collectabove the shale break. Shale break 746 may be an impermeable barrier inhydrocarbon layer 460. In some embodiments, shale break 746 has athickness between about 1 m and about 6 m, between about 2 m and about 5m, or between about 3 m and about 4 m. Production wells 206A betweenheaters 716 and shale break 746 may produce fluids from the upperportion of hydrocarbon layer 460 (above the shale break) and productionwells 206A below the bottommost heaters in the hydrocarbon layer mayproduce fluids from the lower portion of the hydrocarbon layer (belowthe shale break), as depicted in FIG. 133. In some embodiments, two ormore shale breaks may exist in a hydrocarbon layer. In such anembodiment, production wells are placed at or near each of the shalebreaks to produce fluids flowing and collecting above the shale breaks.

In some embodiments, shale break 746 breaks down (is desiccated) as theshale break is heated by heaters 716 on either side of the shale break.As shale break 746 breaks down, the permeability of the shale breakincreases and the shale break allows fluids to flow through the shalebreak. Once fluids are able to flow through shale break 746, productionwells above the shale break may not be needed for production as fluidscan flow to production wells at or near the bottom of hydrocarbon layer460 and be produced there.

In certain embodiments, the bottommost heaters above shale break 746 arelocated between about 2 m and about 10 m from the shale break, betweenabout 4 m and about 8 m from the bottom of the shale break, or betweenabout 5 m and about 7 m from the shale break. Production wells 206A maybe located between about 2 m and about 10 m from the bottommost heatersabove shale break 746, between about 4 m and about 8 m from thebottommost heaters above the shale break, or between about 5 m and about7 m from the bottommost heaters above the shale break. Production wells206A may be located between about 0.5 m and about 8 m from shale break746, between about 1 m and about 5 m from the shale break, or betweenabout 2 m and about 4 m from the shale break.

In some embodiments, heat is provided in production wells 206A and/orproduction wells 206B, depicted in FIGS. 130-133. Providing heat inproduction wells 206A and/or production wells 206B may maintain and/orenhance the mobility of the fluids in the production wells. Heatprovided in production wells 206A and/or production wells 206B maysuperpose with heat from heaters 716 to create the flow path from theheaters to the production wells. In some embodiments, production wells206A and/or production wells 206B include a pump to remove fluids to thesurface of the formation. In some embodiments, the viscosity of fluids(oil) in production wells 206A and/or production wells 206B is loweredusing heaters and/or diluent injection (for example, using a conduit inthe production wells for injecting the diluent).

In certain embodiments, in situ heat treatment of the relativelypermeable formation containing hydrocarbons (for example, the tar sandsformation) includes heating the formation to visbreaking temperatures.For example, the formation may be heated to temperatures between about100° C. and 260° C., between about 150° C. and about 250° C., or betweenabout 200° C. and about 240° C. At visbreaking temperatures, fluids inthe formation have a reduced viscosity (versus their initial viscosityat initial formation temperature) that allows fluids to flow in theformation. The visbroken fluids may have API gravities that arerelatively low (for example, at most about 10°, about 12°, or about 15°API gravity), but the API gravities are higher than the API gravity ofnon-visbroken fluid from the formation. The non-visbroken fluid from theformation may have an API gravity of 7° or less.

In some embodiments, heaters in the formation are operated at full poweroutput to heat the formation to visbreaking temperatures or highertemperatures. Operating at full power may rapidly increase the pressurein the formation. In certain embodiments, fluids are produced from theformation to maintain a pressure in the formation below a selectedpressure as the temperature of the formation increases. In someembodiments, the selected pressure is a fracture pressure of theformation. In certain embodiments, the selected pressure is betweenabout 1000 kPa and about 15000 kPa, between about 2000 kPa and about10000 kPa, or between about 2500 kPa and about 5000 kPa. The fluidsproduced from the formation may be visbroken, mobilized fluids, and/orpyrolyzed fluids. Maintaining the pressure as close to the fracturepressure as possible may minimize the number of production wells neededfor producing fluids from the formation.

In some embodiments, after the formation reaches visbreakingtemperatures, the pressure in the formation is reduced. In certainembodiments, the pressure in the formation is reduced at temperaturesabove visbreaking temperatures. Reducing the pressure at highertemperatures allows more of the hydrocarbons in the formation to beconverted to higher quality hydrocarbons by visbreaking and/orpyrolysis. Allowing the formation to reach higher temperatures beforepressure reduction, however, may increase the amount of carbon dioxideproduced and/or the amount of coking in the formation. For example, insome formations, coking of bitumen (at pressures above 700 kPa) beginsat about 280° C. and reaches a maximum rate at about 340° C. Atpressures below about 700 kPa, the coking rate in the formation isminimal. Allowing the formation to reach higher temperatures beforepressure reduction may decrease the amount of hydrocarbons produced fromthe formation.

In certain embodiments, the temperature in the formation (for example,an average temperature of the formation) when the pressure in theformation is reduced is selected to balance one or more factors. Thefactors considered may include: the quality of hydrocarbons produced,the amount of hydrocarbons produced, the amount of carbon dioxideproduced, the amount hydrogen sulfide produced, the degree of coking inthe formation, and/or the amount of water produced. Experimentalassessments using formation samples and/or simulated assessments basedon the formation properties may be used to assess results of treatingthe formation using the in situ heat treatment process. These resultsmay be used to determine a selected temperature, or temperature range,for when the pressure in the formation is to be reduced. The selectedtemperature, or temperature range, may also be affected by factors suchas, but not limited to, hydrocarbon or oil market conditions and othereconomic factors. In certain embodiments, the selected temperature is ina range between about 275° C. and about 305° C., between about 280° C.and about 300° C., or between about 285° C. and about 295° C.

In certain embodiments, an average temperature in the formation isassessed from an analysis of fluids produced from the formation. Forexample, the average temperature of the formation may be assessed froman analysis of the fluids that have been produced to maintain thepressure in the formation below the fracture pressure of the formation.

In some embodiments, values of the hydrocarbon isomer shift in fluids(for example, gases) produced from the formation is used to indicate theaverage temperature in the formation. Experimental analysis and/orsimulation may be used to assess one or more hydrocarbon isomer shiftsand relate the values of the hydrocarbon isomer shifts to the averagetemperature in the formation. The assessed relation between thehydrocarbon isomer shifts and the average temperature may then be usedin the field to assess the average temperature in the formation bymonitoring one or more of the hydrocarbon isomer shifts in fluidsproduced from the formation. In some embodiments, the pressure in theformation is reduced when the monitored hydrocarbon isomer shift reachesa selected value. The selected value of the hydrocarbon isomer shift maybe chosen based on the selected temperature, or temperature range, inthe formation for reducing the pressure in the formation and theassessed relation between the hydrocarbon isomer shift and the averagetemperature. Examples of hydrocarbon isomer shifts that may be assessedinclude, but are not limited to, n-butane-δ¹³C₄ percentage versuspropane-δ¹³C₃ percentage, n-pentane-δ¹³C₅ percentage versuspropane-δ¹³C₃ percentage, n-pentane-δ¹³C₅ percentage versusn-butane-δ¹³C₄ percentage, and i-pentane-δ¹³C₅ percentage versusi-butane-δ¹³C₄ percentage. In some embodiments, the hydrocarbon isomershift in produced fluids is used to indicate the amount of conversion(for example, amount of pyrolysis) that has taken place in theformation.

In some embodiments, weight percentages of saturates in fluids producedfrom the formation is used to indicate the average temperature in theformation. Experimental analysis and/or simulation may be used to assessthe weight percentage of saturates as a function of the averagetemperature in the formation. For example, SARA (Saturates, Aromatics,Resins, and Asphaltenes) analysis (sometimes referred to asAsphaltene/Wax/Hydrate Deposition analysis) may be used to assess theweight percentage of saturates in a sample of fluids from the formation.In some formations, the weight percentage of saturates has a linearrelationship to the average temperature in the formation. The relationbetween the weight percentage of saturates and the average temperaturemay then be used in the field to assess the average temperature in theformation by monitoring the weight percentage of saturates in fluidsproduced from the formation. In some embodiments, the pressure in theformation is reduced when the monitored weight percentage of saturatesreaches a selected value. The selected value of the weight percentage ofsaturates may be chosen based on the selected temperature, ortemperature range, in the formation for reducing the pressure in theformation and the relation between the weight percentage of saturatesand the average temperature.

In some embodiments, weight percentages of n-C₇ in fluids produced fromthe formation is used to indicate the average temperature in theformation. Experimental analysis and/or simulation may be used to assessthe weight percentages of n-C₇ as a function of the average temperaturein the formation. In some formations, the weight percentages of n-C₇ hasa linear relationship to the average temperature in the formation. Therelation between the weight percentages of n-C₇ and the averagetemperature may then be used in the field to assess the averagetemperature in the formation by monitoring the weight percentages ofn-C₇ in fluids produced from the formation. In some embodiments, thepressure in the formation is reduced when the monitored weightpercentage of n-C₇ reaches a selected value. The selected value of theweight percentage of n-C₇ may be chosen based on the selectedtemperature, or temperature range, in the formation for reducing thepressure in the formation and the relation between the weight percentageof n-C₇ and the average temperature.

The pressure in the formation may be reduced by producing fluids (forexample, visbroken fluids and/or mobilized fluids) from the formation.In some embodiments, the pressure is reduced below a pressure at whichfluids coke in the formation to inhibit coking at pyrolysistemperatures. For example, the pressure is reduced to a pressure belowabout 1000 kPa, below about 800 kPa, or below about 700 kPa (forexample, about 690 kPa). In certain embodiments, the selected pressureis at least about 100 kPa, at least about 200 kPa, or at least about 300kPa. The pressure may be reduced to inhibit coking of asphaltenes orother high molecular weight hydrocarbons in the formation. In someembodiments, the pressure may be maintained below a pressure at whichwater passes through a liquid phase at downhole (formation) temperaturesto inhibit liquid water and dolomite reactions. After reducing thepressure in the formation, the temperature may be increased to pyrolysistemperatures to begin pyrolyzation and/or upgrading of fluids in theformation. The pyrolyzed and/or upgraded fluids may be produced from theformation.

In certain embodiments, the amount of fluids produced at temperaturesbelow visbreaking temperatures, the amount of fluids produced atvisbreaking temperatures, the amount of fluids produced before reducingthe pressure in the formation, and/or the amount of upgraded orpyrolyzed fluids produced may be varied to control the quality andamount of fluids produced from the formation and the total recovery ofhydrocarbons from the formation. For example, producing more fluidduring the early stages of treatment (for example, producing fluidsbefore reducing the pressure in the formation) may increase the totalrecovery of hydrocarbons from the formation while reducing the overallquality (lowering the overall API gravity) of fluid produced from theformation. The overall quality is reduced because more heavyhydrocarbons are produced by producing more fluids at the lowertemperatures. Producing less fluids at the lower temperatures mayincrease the overall quality of the fluids produced from the formationbut may lower the total recovery of hydrocarbons from the formation. Thetotal recovery may be lower because more coking occurs in the formationwhen less fluids are produced at lower temperatures.

In certain embodiments, the formation is heated using isolated cells ofheaters (cells or sections of the formation that are not interconnectedfor fluid flow). The isolated cells may be created by user larger heaterspacings in the formation. For example, large heater spacings may beused in the embodiments depicted in FIGS. 130-133. These isolated cellsmay be produced during early stages of heating (for example, attemperatures below visbreaking temperatures). Because the cells areisolated from other cells in the formation, the pressures in theisolated cells are high and more liquids are producible from theisolated cells. Thus, more liquids may be produced from the formationand a higher total recovery of hydrocarbons may be reached. During laterstages of heating, the heat gradient may interconnect the isolated cellsand pressures in the formation will drop.

In certain embodiments, the heat gradient in the formation is modifiedso that a gas cap is created at or near an upper portion of thehydrocarbon layer. For example, the heat gradient made by heaters 716depicted in the embodiments depicted in FIGS. 130-133 may be modified tocreate the gas cap at or near overburden 458 of hydrocarbon layer 460.The gas cap may push or drive liquids to the bottom of the hydrocarbonlayer so that more liquids may be produced from the formation. In situgeneration of the gas cap may be more efficient than introducingpressurized fluid into the formation. The in situ generated gas capapplies force evenly through the formation with little or no channelingor fingering that may reduce the effectiveness of introduced pressurizedfluid.

In certain embodiments, the number and/or location of production wellsin the formation is varied based on the viscosity of fluids in theformation. The fluid viscosities in the zones may be assessed beforeplacing the production wells in the formation, before heating theformation, and/or after heating the formation. In some embodiments, moreproduction wells are located in zones in the formation that have lowerviscosities. For example, in certain formations, upper portions, orzones, of the formation may have lower viscosities. Thus, moreproduction wells may be located in the upper zones. Locating productionwells in the less viscous zones of the formation allows for betterpressure control in the formation and/or producing higher quality (moreupgraded) oil from the formation.

In some embodiments, zones in the formation with different assessedviscosities are heated at different rates. In certain embodiments, zonesin the formation with higher viscosities are heated at higher heatingrates than zones with lower viscosities. Heating the zones with higherviscosities at the higher heating rates mobilizes and/or upgrades thesezones at a faster rate so that these zones may “catch up” in viscosityand/or quality to the slower heated zones.

In some embodiments, the heater spacing is varied to provide differentheating rates to zones in the formation with different assessedviscosities. For example, denser heater spacings (less spaces betweenheaters) may be used in zones with higher viscosities to heat thesezones at higher heating rates. In some embodiments, a production well(for example, a substantially vertical production well) is located inthe zones with denser heater spacings and higher viscosities. Theproduction well may be used to remove fluids from the formation andrelieve pressure from the higher viscosity zones. In some embodiments,one or more substantially vertical openings, or production wells, arelocated in the higher viscosity zones to allow fluids to drain in thehigher viscosity zones. The draining fluids may be produced from theformation through production wells located near the bottom of the higherviscosity zones.

In certain embodiments, production wells are located in more than onezone in the formation. The zones may have different initialpermeabilities. In certain embodiments, a first zone has an initialpermeability of at least about 1 darcy and a second zone has an initialpermeability of at most about 0.1 darcy. In some embodiments, the firstzone has an initial permeability of between about 1 darcy and about 10darcy. In some embodiments, the second zone has an initial permeabilitybetween about 0.01 darcy and 0.1 darcy. The zones may be separated by asubstantially impermeable barrier (with an initial permeability of atmost about 10 μdarcy or less). Having the production well located inboth zones allows for fluid communication (permeability) between thezones and/or pressure equalization between the zones.

In some embodiments, openings (for example, substantially verticalopenings) are formed between zones with different initial permeabilitiesthat are separated by a substantially impermeable barrier. Bridging thezones with the openings allows for fluid communication (permeability)between the zones and/or pressure equalization between the zones. Insome embodiments, openings in the formation (such as pressure reliefopenings and/or production wells) allow gases or low viscosity fluids torise in the openings. As the gases or low viscosity fluids rise, thefluids may condense or increase viscosity in the openings so that thefluids drain back down the openings to be further upgraded in theformation. Thus, the openings may act as heat pipes by transferring heatfrom the lower portions to the upper portions where the fluids condense.The wellbores may be packed and sealed near or at the overburden toinhibit transport of formation fluid to the surface.

In some embodiments, production of fluids is continued after reducingand/or turning off heating of the formation. The formation may be heatedfor a selected time. For example, the formation may be heated until itreaches a selected average temperature. Production from the formationmay continue after the selected time. Continuing production may producemore fluid from the formation as fluids drain towards the bottom of theformation and/or as fluids are upgraded by passing by hot spots in theformation. In some embodiments, a horizontal production well is locatedat or near the bottom of the formation (or a zone of the formation) toproduce fluids after heating is turned down and/or off.

In certain embodiments, initially produced fluids (for example, fluidsproduced below visbreaking temperatures), fluids produced at visbreakingtemperatures, and/or other viscous fluids produced from the formationare blended with diluent to produce fluids with lower viscosities. Insome embodiments, the diluent includes upgraded or pyrolyzed fluidsproduced from the formation. In some embodiments, the diluent includesupgraded or pyrolyzed fluids produced from another portion of theformation or another formation. In certain embodiments, the amount offluids produced at temperatures below visbreaking temperatures and/orfluids produced at visbreaking temperatures that are blended withupgraded fluids from the formation is adjusted to create a fluidsuitable for transportation and/or use in a refinery. The amount ofblending may be adjusted so that the fluid has chemical and physicalstability. Maintaining the chemical and physical stability of the fluidmay allow the fluid to be transported, reduce pre-treatment processes ata refinery and/or reduce or eliminate the need for adjusting therefinery process to compensate for the fluid.

In certain embodiments, formation conditions (for example, pressure andtemperature) and/or fluid production are controlled to produce fluidswith selected properties. For example, formation conditions and/or fluidproduction may be controlled to produce fluids with a selected APIgravity and/or a selected viscosity. The selected API gravity and/orselected viscosity may be produced by combining fluids produced atdifferent formation conditions (for example, combining fluids producedat different temperatures during the treatment as described above). Asan example, formation conditions and/or fluid production may becontrolled to produce fluids with an API gravity of about 19° and aviscosity of about 0.35 Pa·s (350 cp) at 19° C.

In some embodiments, formation conditions and/or fluid production iscontrolled so that water (for example, connate water) is recondensed inthe treatment area. Recondensing water in the treatment area keeps theheat of condensation in the formation. In addition, having liquid waterin the formation may increase mobility of liquid hydrocarbons (oil) inthe formation. Liquid water may wet rock or other strata in theformation by occupying pores or corners in the strata and creating aslick surface that moves liquid hydrocarbons more readily through theformation.

In certain embodiments, a drive process (for example, a steam injectionprocess such as cyclic steam injection, a steam assisted gravitydrainage process (SAGD), a solvent injection process, a vapor solventand SAGD process, or a carbon dioxide injection process) is used totreat the tar sands formation in addition to the in situ heat treatmentprocess. In some embodiments, heaters are used to create highpermeability zones (or injection zones) in the formation for the driveprocess. Heaters may be used to create a mobilization geometry orproduction network in the formation to allow fluids to flow through theformation during the drive process. For example, heaters may be used tocreate drainage paths between the heaters and production wells for thedrive process. In some embodiments, the heaters are used to provide heatduring the drive process. The amount of heat provided by the heaters maybe small compared to the heat input from the drive process (for example,the heat input from steam injection).

In some embodiments, the in situ heat treatment process creates orproduces the drive fluid in situ. The in situ produced drive fluid maymove through the formation and move mobilized hydrocarbons from oneportion of the formation to another portion of the formation.

In some embodiments, the in situ heat treatment process may provide lessheat to the formation (for example, use a wider heater spacing) if thein situ heat treatment process is followed by the drive process. Thedrive process may be used to increase the amount of heat provided to theformation to compensate for the loss of heat injection.

In some embodiments, the drive process is used to treat the formationand produce hydrocarbons from the formation. The drive process mayrecover a low amount of oil in place from the formation (for example,less than 20% recovery of oil in place from the formation). The in situheat treatment process may be used following the drive process toincrease the recovery of oil in place from the formation. In someembodiments, the drive process preheats the formation for the in situheat treatment process. In some embodiments, the formation is treatedusing the in situ heat treatment process a significant time after theformation has been treated using the drive process. For example, the insitu heat treatment process is used 1 year, 2 years, 3 years, or longerafter a formation has been treated using the drive process. The in situheat treatment process may be used on formations that have been leftdormant after the drive process treatment because further hydrocarbonproduction using the drive process is not possible and/or noteconomically feasible. In some embodiments, the formation remains atleast somewhat preheated from the drive process even after thesignificant time.

In some embodiments, heaters are used to preheat the formation for thedrive process. For example, heaters may be used to create injectivity inthe formation for a drive fluid. The heaters may create high mobilityzones (or injection zones) in the formation for the drive process. Incertain embodiments, heaters are used to create injectivity informations with little or no initial injectivity. Heating the formationmay create a mobilization geometry or production network in theformation to allow fluids to flow through the formation for the driveprocess. For example, heaters may be used to create a fluid productionnetwork between a horizontal heater and a vertical production well. Theheaters used to preheat the formation for the drive process may also beused to provide heat during the drive process.

FIG. 134 depicts a top view representation of an embodiment forpreheating using heaters for the drive process. Injection wells 748 andproduction wells 206 are substantially vertical wells. Heaters 716 arelong substantially horizontal heaters positioned so that the heaterspass in the vicinity of injection wells 748. Heaters 716 intersect thevertical well patterns slightly displaced from the vertical wells.

The vertical location of heaters 716 with respect to injection wells 748and production wells 206 depends on, for example, the verticalpermeability of the formation. In formations with at least some verticalpermeability, injected steam will rise to the top of the permeable layerin the formation. In such formations, heaters 716 may be located nearthe bottom of hydrocarbon layer 460, as shown in FIG. 135. In formationswith very low vertical permeabilities, more than one horizontal heatermay be used with the heaters stacked substantially vertically or withheaters at varying depths in the hydrocarbon layer (for example, heaterpatterns as shown in FIGS. 130-133). The vertical spacing between thehorizontal heaters in such formations may correspond to the distancebetween the heaters and the injection wells. Heaters 716 are located inthe vicinity of injection wells 748 and/or production wells 206 so thatsufficient energy is delivered by the heaters to provide flow rates forthe drive process that are economically viable. The spacing betweenheaters 716 and injection wells 748 or production wells 206 may bevaried to provide an economically viable drive process. The amount ofpreheating may also be varied to provide an economically viable process.

Some formations with little or no initial injectivity (such as karstedformations or karsted layers in formations) may have tight vugs in oneor more layers of the formations. The tight vugs may be vugs filled withviscous fluids such as bitumen or heavy oil. In some embodiments, thevugs have a porosity of at least about 20 porosity units, at least about30 porosity units, or at least about 35 porosity units. The formationmay have a porosity of at most about 15 porosity units, at most about 10porosity units, or at most about 5 porosity units. The tight vugsinhibit steam or other fluids from being injected into the formation orthe layers with tight vugs. In certain embodiments, the karstedformation or karsted layers of the formation are treated using the insitu heat treatment process. Heating of these formations or layers maydecrease the viscosity of the fluids in the tight vugs and allow thefluids to drain (for example, mobilize the fluids).

In certain embodiments, only the karsted layers of the formation aretreated using the in situ heat treatment process. Other non-karstedlayers of the formation may be used as seals for the in situ heattreatment process.

In some embodiments, the drive process is used after the in situ heattreatment of the karsted formation or karsted layers. In someembodiments, heaters are used to preheat the karsted formation orkarsted layers to create injectivity in the formation.

In certain embodiments, the karsted formation or karsted layers areheated to temperatures below the decomposition temperature of rock (forexample, dolomite) in the formation (for example, temperatures at mostabout 400° C.). In some embodiments, the karsted formation or karstedlayers are heated to temperatures above the decomposition temperature ofdolomite in the formation. At temperatures above the dolomitedecomposition temperature, the dolomite may decompose to produce carbondioxide. The decomposition of the dolomite and the carbon dioxideproduction may create permeability in the formation and mobilize viscousfluids in the formation. In some embodiments, the produced carbondioxide is maintained in the formation to produce a gas cap in theformation. The carbon dioxide may be allowed to rise to the upperportions of the karsted layers to produce the gas cap.

In some embodiments, heaters are used to produce and/or maintain the gascap in the formation for the in situ heat treatment process and/or thedrive process. The gas cap may drive fluids from upper portions to lowerportions of the formation and/or from portions of the formation towardsportions of the formation at lower pressures (for example, portions withproduction wells). In some embodiments, little or no heating is providedin the portions of the formation with the gas cap. In some embodiments,heaters in the gas cap are turned down and/or off after formation of thegas cap. Using less heating in the gas cap may reduce the energy inputinto the formation and increase the efficiency of the in situ heattreatment process and/or the drive process. In some embodiments,production wells and/or heater wells that are located in the gas capportion of the formation may be used for injection of fluid (forexample, steam) to maintain the gas cap.

In some embodiments, the production front of the drive process followsbehind the heat front of the in situ heat treatment process. In someembodiments, areas behind the production front are further heated toproduce more fluids from the formation. Further heating behind theproduction front may also maintain the gas cap behind the productionfront and/or maintain quality in the production front of the driveprocess.

In certain embodiments, the drive process is used before the in situheat treatment of the formation. In some embodiments, the drive processis used to mobilize fluids in a first section of the formation. Themobilized fluids may then be pushed into a second section by heating thefirst section with heaters. Fluids may be produced from the secondsection. In some embodiments, the fluids in the second section arepyrolyzed and/or upgraded using the heaters.

In formations with low permeabilities, the drive process may be used tocreate a “gas cushion” or pressure sink before the in situ heattreatment process. The gas cushion may inhibit pressures from increasingquickly to fracture pressure during the in situ heat treatment process.The gas cushion may provide a path for gases to escape or travel duringearly stages of heating during the in situ heat treatment process.

In some embodiments, the drive process (for example, the steam injectionprocess) is used to mobilize fluids before the in situ heat treatmentprocess. Steam injection may be used to get hydrocarbons (oil) away fromrock or other strata in the formation. The steam injection may mobilizethe oil without significantly heating the rock.

In some embodiments, injection of a fluid (for example, steam or carbondioxide) may consume heat in the formation and cool the formationdepending on the pressure in the formation. In some embodiments, theinjected fluid is used to recover heat from the formation. The recoveredheat may be used in surface processing of fluids and/or to preheat otherportions of the formation using the drive process.

FIG. 136 depicts a representation of an embodiment for producinghydrocarbons from a hydrocarbon containing formation (for example, a tarsands formation). Hydrocarbon layer 460 includes one or more portionswith heavy hydrocarbons. Hydrocarbons may be produced from hydrocarbonlayer 460 using more than one process. In certain embodiments,hydrocarbons are produced from a first portion of hydrocarbon layer 460using a steam injection process (for example, cyclic steam injection orsteam-assisted gravity drainage) and a second portion of the hydrocarbonlayer using an in situ heat treatment process. In the steam injectionprocess, steam is injected into the first portion of hydrocarbon layer460 through injection well 748. First hydrocarbons are produced from thefirst portion through production well 206A. The first hydrocarbonsinclude hydrocarbons mobilized by the injection of steam. In certainembodiments, the first hydrocarbons have an API gravity of at most 15°,at most 10°, at most 8°, or at most 6°.

Heaters 716 are used to heat the second portion of hydrocarbon layer 460to mobilization, visbreaking, and/or pyrolysis temperatures. Secondhydrocarbons are produced from the second portion through productionwell 206B. In some embodiments, the second hydrocarbons include at leastsome pyrolyzed hydrocarbons. In certain embodiments, the secondhydrocarbons have an API gravity of at least 15°, at least 20°, or atleast 25°.

In some embodiments, the first portion of hydrocarbon layer 460 istreated using heaters after the steam injection process. Heaters may beused to increase the temperature of the first portion and/or treat thefirst portion using an in situ heat treatment process. Secondhydrocarbons (including at least some pyrolyzed hydrocarbons) may beproduced from the first portion through production well 206A.

In some embodiments, the second portion of hydrocarbon layer 460 istreated using the steam injection process before using heaters 716 totreat the second portion. The steam injection process may be used toproduce some fluids (for example, first hydrocarbons or hydrocarbonsmobilized by the steam injection) through production well 206B from thesecond portion and/or preheat the second portion before using heaters716. In some embodiments, the steam injection process may be used afterusing heaters 716 to treat the first portion and/or the second portion.

Producing hydrocarbons through both processes increases the totalrecovery of hydrocarbons from hydrocarbon layer 460 and may be moreeconomical than using either process alone. In some embodiments, thefirst portion is treated with the in situ heat treatment process afterthe steam injection process is completed. For example, after the steaminjection process no longer produces viable amounts of hydrocarbon fromthe first portion, the in situ heat treatment process may be used on thefirst portion.

Steam is provided to injection well 748 from facility 750. Facility 750is a steam and electricity cogeneration facility. Facility 750 may burnhydrocarbons in generators to make electricity. Facility 750 may burngaseous and/or liquid hydrocarbons to make electricity. The electricitygenerated is used to provide electrical power for heaters 716. Wasteheat from the generators is used to make steam. In some embodiments,some of the hydrocarbons produced from the formation are used to providegas for heaters 716, if the heaters utilize gas to provide heat to theformation. The amount of electricity and steam generated by facility 750may be controlled to vary the production rate and/or quality ofhydrocarbons produced from the first portion and/or the second portionof hydrocarbon layer 460. The production rate and/or quality ofhydrocarbons produced from the first portion and/or the second portionmay be varied to produce a selected API gravity in a mixture made byblending the first hydrocarbons with the second hydrocarbons. The firsthydrocarbon and the second hydrocarbons may be blended after productionto produce the selected API gravity. The production from the firstportion and/or the second portion may be varied in response to changesin the marketplace for either first hydrocarbons, second hydrocarbons,and/or a mixture of the first and second hydrocarbons.

First hydrocarbons produced from production well 206A and/or secondhydrocarbons produced from production well 206B may be used as fuel forfacility 750. In some embodiments, first hydrocarbons and/or secondhydrocarbons are treated (for example, removing undesirable products)before being used as fuel for facility 750. The amount of firsthydrocarbons and second hydrocarbons used as fuel for facility 750 maybe determined, for example, by economics for the overall process, themarketplace for either first or second hydrocarbons, availability oftreatment facilities for either first or second hydrocarbons, and/ortransportation facilities available for either first or secondhydrocarbons. In some embodiments, most or all the hydrocarbon gasproduced from hydrocarbon layer 460 is used as fuel for facility 750.Burning all the hydrocarbon gas in facility 750 eliminates the need fortreatment and/or transportation of gases produced from hydrocarbon layer460.

The produced first hydrocarbons and the second hydrocarbons may betreated and/or blended in facility 752. In some embodiments, the firstand second hydrocarbons are blended to make a mixture that istransportable through a pipeline. In some embodiments, the first andsecond hydrocarbons are blended to make a mixture that is useable as afeedstock for a refinery. The amount of first and second hydrocarbonsproduced may be varied based on changes in the requirements fortreatment and/or blending of the hydrocarbons. In some embodiments,treated hydrocarbons are used in facility 750.

In some embodiments, the steam injection process and the in situ heattreatment process (for example, the in situ conversion process) are usedsynergistically in different layers (for example, vertically displacedlayers) in the formation. For example, in a karsted formation, differentzones or layers in the formation may have different oil saturations,water saturations, porosities, and/or permeabilities. Some layers mayhave good steam injectivities while others have near zero steaminjectivity. The steam injectivity may depend on the water saturation ofthe zone and the permeability. Thus, varying the use of the steaminjection process and the in situ heat treatment process in these layersmay be economically advantageous by, for example, producing morehydrocarbons with less energy input into the formation. The steaminjection process may include steam drive, cyclic steam injection, SAGD,or other process of steam injection into the formation.

FIG. 137 depicts a representation of an embodiment for producinghydrocarbons from multiple layers in a tar sands formation. Hydrocarbonlayers 460A,B,C include one or more portions with heavy hydrocarbons.Hydrocarbon layers 460A,B,C may have different oil saturations, watersaturations, porosities, and/or permeabilities. In one embodiment,hydrocarbon layers 460A,C have lower oil saturations, higher watersaturations, and lower porosities than hydrocarbon layer 460B. The steaminjection process may be used in hydrocarbon layers 460A,C usinginjection wells 748A,C and production wells 206A,C. The in situ heattreatment process may be used in hydrocarbon layer 460B using heaters716 and production well 206B. In some embodiments, the in situ heattreatment process is used in hydrocarbon layer 460B, which has high oilsaturation and low steam injectivity. After the in situ heat treatmentof hydrocarbon layer 460B, the layer may have steam injectivity and betreated using the steam injection process.

Injecting steam into hydrocarbon layers 460A,C above and belowhydrocarbon layer 460B may increase the efficiency of producinghydrocarbons from the formation. Steam injection in hydrocarbon layers460A,C lowers the viscosity and increases the pressures in these layersso that hydrocarbons move into hydrocarbon layer 460B. Heat fromhydrocarbon layer 460B may conduct and/or convect into hydrocarbonlayers 460A,C and preheat these layers to lower the oil viscosity and/orincrease the steam injectivity in hydrocarbon layers 460A,C.Additionally, some steam may rise from hydrocarbon layer 460C intohydrocarbon layer 460B. This steam may provide additional heat andincreased mobilization in hydrocarbon layer 460B. The steam injectionprocess and/or the in situ heat treatment process may be used (forexample, varied) as described above for the embodiment depicted in FIG.136. Hydrocarbons produced from any of hydrocarbon layers 460A,B,C maybe used and/or processed in facility 750 and/or facility 752, asdescribed above for the embodiment depicted in FIG. 136.

In some embodiments, impermeable shale layers exist between hydrocarbonlayer 460B and hydrocarbon layers 460A,C. Using the in situ heattreatment process on hydrocarbon layer 460B may desiccate the shalelayers and increase the permeability of the shale layers to allow fluidflux through the shale layers. This increased permeability in the shalelayers allows mobilized hydrocarbons to flow from hydrocarbon layer 460Ainto hydrocarbon layer 460B. These hydrocarbons may be upgraded andproduced in hydrocarbon layer 460B.

FIG. 138 depicts an embodiment for heating and producing from theformation with the temperature limited heater in a production wellbore.Production conduit 754 is located in wellbore 756. In certainembodiments, a portion of wellbore 756 is located substantiallyhorizontally in formation 758. In some embodiments, the wellbore islocated substantially vertically in the formation. In an embodiment,wellbore 756 is an open wellbore (an uncased wellbore). In someembodiments, the wellbore has a casing or liner with perforations oropenings to allow fluid to flow into the wellbore.

Conduit 754 may be made from carbon steel or more corrosion resistantmaterials such as stainless steel. Conduit 754 may include apparatus andmechanisms for gas lifting or pumping produced oil to the surface. Forexample, conduit 754 includes gas lift valves used in a gas liftprocess. Examples of gas lift control systems and valves are disclosedin U.S. Pat. No. 6,715,550 to Vinegar et al. and U.S. Patent ApplicationPublication Nos. 2002-0036085 to Bass et al. and 2003-0038734 to Hirschet al., each of which is incorporated by reference as if fully set forthherein. Conduit 754 may include one or more openings (perforations) toallow fluid to flow into the production conduit. In certain embodiments,the openings in conduit 754 are in a portion of the conduit that remainsbelow the liquid level in wellbore 756. For example, the openings are ina horizontal portion of conduit 754.

Heater 760 is located in conduit 754, as shown in FIG. 138. In someembodiments, heater 760 is located outside conduit 754, as shown in FIG.139. The heater located outside the production conduit may be coupled(strapped) to the production conduit. In some embodiments, more than oneheater (for example, two, three, or four heaters) are placed aboutconduit 754. The use of more than one heater may reduce bowing orflexing of the production conduit caused by heating on only one side ofthe production conduit. In an embodiment, heater 760 is a temperaturelimited heater. Heater 760 provides heat to reduce the viscosity offluid (such as oil or hydrocarbons) in and near wellbore 756. In certainembodiments, heater 760 raises the temperature of the fluid in wellbore756 up to a temperature of 250° C. or less (for example, 225° C., 200°C., or 150° C.). Heater 760 may be at higher temperatures (for example,275° C., 300° C., or 325° C.) because the heater provides heat toconduit 754 and there is some temperature differential between theheater and the conduit. Thus, heat produced from the heater does notraise the temperature of fluids in the wellbore above 250° C.

In certain embodiments, heater 760 includes ferromagnetic materials suchas Carpenter Temperature Compensator “32”, Alloy 42-6, Alloy 52, Invar36, or other iron-nickel or iron-nickel-chromium alloys. In certainembodiments, nickel or nickel-chromium alloys are used in heater 760. Insome embodiments, heater 760 includes a composite conductor with a morehighly conductive material such as copper on the inside of the heater toimprove the turndown ratio of the heater. Heat from heater 760 heatsfluids in or near wellbore 756 to reduce the viscosity of the fluids andincrease a production rate through conduit 754.

In certain embodiments, portions of heater 760 above the liquid level inwellbore 756 (such as the vertical portion of the wellbore depicted inFIGS. 138 and 139) have a lower maximum temperature than portions of theheater located below the liquid level. For example, portions of heater760 above the liquid level in wellbore 756 may have a maximumtemperature of 100° C. while portions of the heater located below theliquid level have a maximum temperature of 250° C. In certainembodiments, such a heater includes two or more ferromagnetic sectionswith different Curie temperatures and/or phase transformationtemperature ranges to achieve the desired heating pattern. Providingless heat to portions of wellbore 756 above the liquid level and closerto the surface may save energy.

In certain embodiments, heater 760 is electrically isolated on theheater's outside surface and allowed to move freely in conduit 754. Insome embodiments, electrically insulating centralizers are placed on theoutside of heater 760 to maintain a gap between conduit 754 and theheater.

In some embodiments, heater 760 is cycled (turned on and off) so thatfluids produced through conduit 754 are not overheated. In anembodiment, heater 760 is turned on for a specified amount of time untila temperature of fluids in or near wellbore 756 reaches a desiredtemperature (for example, the maximum temperature of the heater). Duringthe heating time (for example, 10 days, 20 days, or 30 days), productionthrough conduit 754 may be stopped to allow fluids in the formation to“soak” and obtain a reduced viscosity. After heating is turned off orreduced, production through conduit 754 is started and fluids from theformation are produced without excess heat being provided to the fluids.During production, fluids in or near wellbore 756 will cool down withoutheat from heater 760 being provided. When the fluids reach a temperatureat which production significantly slows down, production is stopped andheater 760 is turned back on to reheat the fluids. This process may berepeated until a desired amount of production is reached. In someembodiments, some heat at a lower temperature is provided to maintain aflow of the produced fluids. For example, low temperature heat (forexample, 100° C., 125° C., or 150° C.) may be provided in the upperportions of wellbore 756 to keep fluids from cooling to a lowertemperature.

FIG. 140 depicts an embodiment of a heating/production assembly that maybe located in a wellbore for gas lifting. Heating/production assembly762 may be located in a wellbore in the formation (for example, wellbore756 depicted in FIG. 138 or 139). Conduit 754 is located inside casing530. In an embodiment, conduit 754 is coiled tubing such as 6 cmdiameter coiled tubing. Casing 530 has a diameter between 10 cm and 25cm (for example, a diameter of 14 cm, 16 cm, or 18 cm). Heater 760 iscoupled to an end of conduit 754. In some embodiments, heater 760 islocated inside conduit 754. In some embodiments, heater 760 is aresistive portion of conduit 754. In some embodiments, heater 760 iscoupled to a length of conduit 754.

Opening 764 is located at or near a junction of heater 760 and conduit754. In some embodiments, opening 764 is a slot or a slit in conduit754. In some embodiments, opening 764 includes more than one opening inconduit 754. Opening 764 allows production fluids to flow into conduit754 from a wellbore. Perforated casing 766 allows fluids to flow intothe heating/production assembly 762. In certain embodiments, perforatedcasing 766 is a wire wrapped screen. In one embodiment, perforatedcasing 766 is a 9 cm diameter wire wrapped screen.

Perforated casing 766 may be coupled to casing 530 with packing material532. Packing material 532 inhibits fluids from flowing into casing 530from outside perforated casing 766. Packing material 532 may also beplaced inside casing 530 to inhibit fluids from flowing up the annulusbetween the casing and conduit 754. Seal assembly 768 is used to sealconduit 754 to packing material 532. Seal assembly 768 may fix aposition of conduit 754 along a length of a wellbore. In someembodiments, seal assembly 768 allows for unsealing of conduit 754 sothat the production conduit and heater 760 may be removed from thewellbore.

Feedthrough 770 is used to pass lead-in cable 636 to supply power toheater 760. Lead-in cable 636 may be secured to conduit 754 with clamp772. In some embodiments, lead-in cable 636 passes through packingmaterial 532 using a separate feedthrough.

A lifting gas (for example, natural gas, methane, carbon dioxide,propane, and/or nitrogen) may be provided to the annulus between conduit754 and casing 530. Valves 774 are located along a length of conduit 754to allow gas to enter the production conduit and provide for gas liftingof fluids in the production conduit. The lifting gas may mix with fluidsin conduit 754 to lower the density of the fluids and allow for gaslifting of the fluids out of the formation. In certain embodiments,valves 774 are located in or near the overburden section of theformation so that gas lifting is provided in the overburden section. Insome embodiments, fluids are produced through the annulus betweenconduit 754 and casing 530 and the lifting gas is supplied throughvalves 774.

In an embodiment, fluids are produced using a pump coupled to conduit754. The pump may be a submersible pump (for example, an electric or gaspowered submersible pump). In some embodiments, a heater is coupled toconduit 754 to maintain the reduced viscosity of fluids in the conduitand/or the pump.

In certain embodiments, an additional conduit such as an additionalcoiled tubing conduit is placed in the formation. Sensors may be placedin the additional conduit. For example, a production logging tool may beplaced in the additional conduit to identify locations of producingzones and/or to assess flow rates. In some embodiments, a temperaturesensor (for example, a distributed temperature sensor, a fiber opticsensor, and/or an array of thermocouples) is placed in the additionalconduit to determine a subsurface temperature profile.

Some embodiments of the heating/production assembly are used in a wellthat preexists (for example, the heating/production assembly isretrofitted for a preexisting production well, heater well, ormonitoring well). An example of the heating/production assembly that maybe used in the preexisting well is depicted in FIG. 141. Somepreexisting wells include a pump. The pump in the preexisting well maybe left in the heating/production well retrofitted with theheating/production assembly.

FIG. 141 depicts an embodiment of the heating/production assembly thatmay be located in the wellbore for gas lifting. In FIG. 141, conduit 754is located in outside production conduit 776. In an embodiment, outsideproduction conduit 776 is 11.4 cm diameter production tubing. Casing 530has a diameter of 24.4 cm. Perforated casing 766 has a diameter of 11.4cm. Seal assembly 768 seals conduit 754 inside outside productionconduit 776. In an embodiment, pump 778 is a jet pump such as abottomhole assembly jet pump.

FIG. 142 depicts another embodiment of a heating/production assemblythat may be located in a wellbore for gas lifting. Heater 760 is locatedinside perforated casing 766. Heater 760 is coupled to lead-in cable 636through a feedthrough in packing material 532. Production conduit 754extends through packing material 532. Pump 778 is located along conduit754. In certain embodiments, pump 778 is a jet pump or a bean pump.Valves 774 are located along conduit 754 for supplying lift gas to theconduit.

In some embodiments, heat is inhibited from transferring into conduit754. FIG. 143 depicts an embodiment of conduit 754 and heaters 760 thatinhibit heat transfer into the conduit. Heaters 760 are coupled toconduit 754. Heaters 760 include ferromagnetic sections 486 andnon-ferromagnetic sections 488. Ferromagnetic sections 486 provide heatat a temperature that reduces the viscosity of fluids in or near awellbore. Non-ferromagnetic sections 488 provide little or no heat. Incertain embodiments, ferromagnetic sections 486 and non-ferromagneticsections 488 are 6 m in length. In some embodiments, ferromagneticsections 486 and non-ferromagnetic sections 488 are between 3 m and 12 min length, between 4 m and 11 m in length, or between 5 m and 10 m inlength. In certain embodiments, non-ferromagnetic sections 488 includeperforations 780 to allow fluids to flow to conduit 754. In someembodiments, heater 760 is positioned so that perforations are notneeded to allow fluids to flow to conduit 754.

Conduit 754 may have perforations 780 to allow fluid to enter theconduit. Perforations 780 coincide with non-ferromagnetic sections 488of heater 760. Sections of conduit 754 that coincide with ferromagneticsections 486 include insulation conduit 782. Conduit 782 may be a vacuuminsulated tubular. For example, conduit 782 may be a vacuum insulatedproduction tubular available from Oil Tech Services, Inc. (Houston,Tex., U.S.A.). Conduit 782 inhibits heat transfer into conduit 754 fromferromagnetic sections 486. Limiting the heat transfer into conduit 754reduces heat loss and/or inhibits overheating of fluids in the conduit.In an embodiment, heater 760 provides heat along an entire length of theheater and conduit 754 includes conduit 782 along an entire length ofthe production conduit.

In certain embodiments, more than one wellbore 756 is used to produceheavy oils from a formation using the temperature limited heater. FIG.144 depicts an end view of an embodiment with wellbores 756 located inhydrocarbon layer 460. Portions of wellbores 756 are placedsubstantially horizontally in a triangular pattern in hydrocarbon layer460. In certain embodiments, wellbores 756 have a spacing of 30 m to 60m, 35 m to 55 m, or 40 m to 50 m. Wellbores 756 may include productionconduits and heaters previously described. Fluids may be heated andproduced through wellbores 756 at an increased production rate above acold production rate for the formation. Production may continue for aselected time (for example, 5 years to 10 years, 6 years to 9 years, or7 years to 8 years) until heat produced from each of wellbores 756begins to overlap (superposition of heat begins). At such a time, heatfrom lower wellbores (such as wellbores 756 near the bottom ofhydrocarbon layer 460) is continued, reduced, or turned off whileproduction is continued. Production in upper wellbores (such aswellbores 756 near the top of hydrocarbon layer 460) may be stopped sothat fluids in the hydrocarbon layer drain towards the lower wellbores.In some embodiments, power is increased to the upper wellbores and thetemperature raised above the Curie temperature and/or the phasetransformation temperature range to increase the heat injection rate.Draining fluids in the formation in such a process increases totalhydrocarbon recovery from the formation.

In an embodiment, a temperature limited heater is used in a horizontalheater/production well. The temperature limited heater may provideselected amounts of heat to the “toe” and the “heel” of the horizontalportion of the well. More heat may be provided to the formation throughthe toe than through the heel, creating a “hot portion” at the toe and a“warm portion” at the heel. Formation fluids may be formed in the hotportion and produced through the warm portion, as shown in FIG. 145.

FIG. 145 depicts an embodiment of a heater well for selectively heatinga formation. Heat source 202 is placed in opening 522 in hydrocarbonlayer 460. In certain embodiments, opening 522 is a substantiallyhorizontal opening in hydrocarbon layer 460. Perforated casing 766 isplaced in opening 522. Perforated casing 766 provides support thatinhibits hydrocarbon and/or other material in hydrocarbon layer 460 fromcollapsing into opening 522. Perforations in perforated casing 766 allowfor fluid flow from hydrocarbon layer 460 into opening 522. Heat source202 may include hot portion 784. Hot portion 784 is a portion of heatsource 202 that operates at higher heat output than adjacent portions ofthe heat source. For example, hot portion 784 may output between 650 W/mand 1650 W/m, 650 W/m and 1500 W/m, or 800 W/m and 1500 W/m. Hot portion784 may extend from a “heel” of the heat source to the “toe” of the heatsource. The heel of the heat source is the portion of the heat sourceclosest to the point at which the heat source enters a hydrocarbonlayer. The toe of the heat source is the end of the heat source furthestfrom the entry of the heat source into the hydrocarbon layer.

In an embodiment, heat source 202 includes warm portion 786. Warmportion 786 is a portion of heat source 202 that operates at lower heatoutputs than hot portion 784. For example, warm portion 786 may outputbetween 30 W/m and 1000 W/m, 30 W/m and 750 W/m, or 100 W/m and 750 W/m.Warm portion 786 may be located closer to the heel of heat source 202.In certain embodiments, warm portion 786 is a transition portion (forexample, a transition conductor) between hot portion 784 and overburdenportion 788. Overburden portion 788 is located in overburden 458.Overburden portion 788 provides a lower heat output than warm portion786. For example, overburden portion 788 may output between 10 W/m and90 W/m, 15 W/m and 80 W/m, or 25 W/m and 75 W/m. In some embodiments,overburden portion 788 provides as close to no heat (0 W/m) as possibleto overburden 458. Some heat, however, may be used to maintain fluidsproduced through opening 522 in a vapor phase or at elevated temperaturein overburden 458.

In certain embodiments, hot portion 784 of heat source 202 heatshydrocarbons to high enough temperatures to result in coke 790 formingin hydrocarbon layer 460. Coke 790 may occur in an area surroundingopening 522. Warm portion 786 may be operated at lower heat outputs sothat coke does not form at or near the warm portion of heat source 202.Coke 790 may extend radially from opening 522 as heat from heat source202 transfers outward from the opening. At a certain distance, however,coke 790 no longer forms because temperatures in hydrocarbon layer 460at the certain distance will not reach coking temperatures. The distanceat which no coke forms is a function of heat output (W/m from heatsource 202), type of formation, hydrocarbon content in the formation,and/or other conditions in the formation.

The formation of coke 790 inhibits fluid flow into opening 522 throughthe coking. Fluids in the formation may, however, be produced throughopening 522 at the heel of heat source 202 (for example, at warm portion786 of the heat source) where there is little or no coke formation. Thelower temperatures at the heel of heat source 202 reduce the possibilityof increased cracking of formation fluids produced through the heel.Fluids may flow in a horizontal direction through the formation moreeasily than in a vertical direction. Typically, horizontal permeabilityin a relatively permeable formation is approximately 5 to 10 timesgreater than vertical permeability. Thus, fluids flow along the lengthof heat source 202 in a substantially horizontal direction. Producingformation fluids through opening 522 is possible at earlier times thanproducing fluids through production wells in hydrocarbon layer 460. Theearlier production times through opening 522 is possible becausetemperatures near the opening increase faster than temperatures furtheraway due to conduction of heat from heat source 202 through hydrocarbonlayer 460. Early production of formation fluids may be used to maintainlower pressures in hydrocarbon layer 460 during start-up heating of theformation. Start-up heating of the formation is the time of heatingbefore production begins at production wells in the formation. Lowerpressures in the formation may increase liquid production from theformation. In addition, producing formation fluids through opening 522may reduce the number of production wells needed in the formation.

In some embodiments, a temperature limited heater positioned in awellbore heats steam that is provided to the wellbore. The heated steammay be introduced into a portion of the formation. In certainembodiments, the heated steam may be used as a heat transfer fluid toheat a portion of the formation. In some embodiments, the steam is usedto solution mine desired minerals from the formation. In someembodiments, the temperature limited heater positioned in the wellboreheats liquid water that is introduced into a portion of the formation.

In an embodiment, the temperature limited heater includes ferromagneticmaterial with a selected Curie temperature and/or a selected phasetransformation temperature range. The use of a temperature limitedheater may inhibit a temperature of the heater from increasing beyond amaximum selected temperature (for example, at or about the Curietemperature and/or the phase transformation temperature range). Limitingthe temperature of the heater may inhibit potential burnout of theheater. The maximum selected temperature may be a temperature selectedto heat the steam to above or near 100% saturation conditions,superheated conditions, or supercritical conditions. Using a temperaturelimited heater to heat the steam may inhibit overheating of the steam inthe wellbore. Steam introduced into a formation may be used forsynthesis gas production, to heat the hydrocarbon containing formation,to carry chemicals into the formation, to extract chemicals or mineralsfrom the formation, and/or to control heating of the formation.

A portion of the formation where steam is introduced or that is heatedwith steam may be at significant depths below the surface (for example,greater than about 1000 m, about 250°, or about 5000 m below thesurface). If steam is heated at the surface of the formation andintroduced to the formation through a wellbore, a quality of the heatedsteam provided to the wellbore at the surface may have to be relativelyhigh to accommodate heat losses to the wellbore casing and/or theoverburden as the steam travels down the wellbore. Heating the steam inthe wellbore may allow the quality of the steam to be significantlyimproved before the steam is provided to the formation. A temperaturelimited heater positioned in a lower section of the overburden and/oradjacent to a target zone of the formation may be used to controllablyheat steam to improve the quality of the steam injected into theformation and/or inhibit condensation along the length of the heater. Incertain embodiments, the temperature limited heater improves the qualityof the steam injected and/or inhibits condensation in the wellbore forlong steam injection wellbores (especially for long horizontal steaminjection wellbores).

A temperature limited heater positioned in a wellbore may be used toheat the steam to above or near 100% saturation conditions orsuperheated conditions. In some embodiments, a temperature limitedheater may heat the steam so that the steam is above or nearsupercritical conditions. The static head of fluid above the temperaturelimited heater may facilitate producing 100% saturation, superheated,and/or supercritical conditions in the steam. Supercritical or nearsupercritical steam may be used to strip hydrocarbon material and/orother materials from the formation. In certain embodiments, steamintroduced into the formation may have a high density (for example, aspecific gravity of about 0.8 or above). Increasing the density of thesteam may improve the ability of the steam to strip hydrocarbon materialand/or other materials from the formation.

In some embodiments, the tar sands formation may be treated by the insitu heat treatment process to produce pyrolyzed product from theformation. A significant amount of carbon in the form of coke may remainin tar sands formation when production of pyrolysis product from theformation is complete. In some embodiments, the coke in the formationmay be utilized to produce heat and/or additional products from theheated coke containing portions of the formation.

In some embodiments, air, oxygen enriched air, and/or other oxidants maybe introduced into the treatment area that has been pyrolyzed to reactwith the coke in the treatment area. The temperature of the treatmentarea may be sufficiently hot to support burning of the coke withoutadditional energy input from heaters. The oxidation of the coke maysignificantly heat the portion of the formation. Some of the heat maytransfer to portions of the formation adjacent to the treatment area.The transferred heat may mobilize fluids in portions of the formationadjacent to the treatment area. The mobilized fluids may flow into andbe produced from production wells near the perimeter of the treatmentarea.

Gases produced from the formation heated by combusting coke in theformation may be at high temperature. The hot gases may be utilized inan energy recovery cycle (for example, a Kalina cycle or a Rankinecycle) to produce electricity.

The air, oxygen enriched air and/or other oxidants may be introducedinto the formation for a sufficiently long period of time to heat aportion of the treatment area to a desired temperature sufficient toallow for the production of synthesis gas of a desired composition. Thetemperature may be from 500° C. to about 1000° C. or higher. When thetemperature of the portion is at or near the desired temperature, asynthesis gas generating fluid, such as water, may be introduced intothe formation to result in the formation of synthesis gas. Synthesis gasproduced from the formation may be sent to a treatment facility and/orbe sent through a pipeline to a desired location. During introduction ofthe synthesis gas generating fluid, the introduction of air, oxygenenriched air, and/or other oxidants may be stopped, reduced, ormaintained. If the temperature of the formation reduces so that thesynthesis gas produced from the formation does not have the desiredcomposition, introduction of the syntheses gas generating fluid may bestopped or reduced, and the introduction of air, enriched air and/orother oxidants may be started or increased so that oxidation of coke inthe formation reheats portions of the treatment area. The introductionof oxidant to heat the formation and the introduction of synthesis gasgenerating fluid to produce synthesis gas may be cycled until all or asignificant portion of the treatment area is treated.

In some embodiments, temperature limited heaters are manufactured fromaustenitic stainless steels. These austenitic steels may include alloyswith a face centered cubic (fcc) austenite phase being the primaryphase. The fcc austenite phase may be stabilized by controlling theFe—Cr—Ni and/or the Fe₁₈Cr₈—Ni concentration. Strength of the austeniticphase may be increased by incorporating other alloys in the fcc lattice.For low-temperature applications, the strength may be raised by addingalloying elements that increase the strength of the fcc lattice. Thistype of strengthening may be referred to as “solid solutionstrengthening”. As the use temperature is increased, however, alloyingelements in the austenite phase may react to form new phases such asM₂₃C₆, where M includes chromium and other elements that can formcarbides. Other phases may form in austenite containing elements fromColumns 4-13 of the Periodic Table. Examples of such elements include,but are not limited to, niobium, titanium, vanadium, tungsten, aluminum,or mixtures thereof. The size and distribution of various phases andtheir stability in the desired use temperature range determines themechanical properties of the stainless steel. Nano-scale dispersions ofprecipitates such as carbides may produce the highest strength at hightemperatures, but due to the size of the carbides, they may becomeunstable and coarsen. Alloys containing nano-scale precipitatedispersions may be unstable at temperatures of at least 750° C. Since,heaters may heat a subsurface formation to temperatures at least 700°C., heaters having improved strength alloys capable of withstandingtemperatures of at least 700° C. are desired.

In some embodiments, iron, chromium, and nickel alloys containingmanganese, copper and tungsten, in combination with niobium, carbon andnitrogen, may maintain a finer grain size despite high temperaturesolution annealing or processing. Such behavior may be beneficial inreducing a heat-affected-zone in welded material. Highersolution-annealing temperatures are particularly important for achievingthe best metal carbide (MC) nanocarbide. For example, niobium carbidenanocarbide strengthens during high-temperature creep service, and sucheffects are amplified (finer nanocarbide structures that are stable) bycompositions of the improved alloys. Tubing and canister applicationsthat include the composition of the improved alloys and are wroughtprocessed result in stainless steels that may be able to age-hardenduring service at 700° C. to 800° C. Improved alloys may be able toage-harden even more if the alloys are cold-strained prior tohigh-temperature service, but such cold-prestraining is not necessaryfor good high temperature properties or age-hardening. Some prior artalloys, such as NF709 require cold-prestraining to achieve good hightemperature creep properties, and this is a disadvantage in particularbecause after such alloys are welded, the advantages of thecold-prestraining in the weld heat effected zone are lost. Other priorart alloys are adversely effected by cold-prestraining with respect tohigh-temperature strength and long-term durability. Thus, coldprestraining may be limited or not permitted by, for example,construction codes.

In some embodiments of the new alloy compositions, the alloy may be coldworked by, for example, twenty percent, and the yield strength at 800°C. is not changed by more than twenty percent from yield strength at800° C. of freshly annealed alloy.

The improved alloys described herein are suitable for low temperatureapplications, for example, cryogenic applications. The improved alloyswhich have strength and sufficient ductility at temperatures of, forexample, −50° C. to −200° C., also retain strength at highertemperatures than many alloys often used in cryogenic applications, suchas 201LN and YUS130, thus for services such as liquefied natural gas,where a failure may result in a fire, the improved alloy would retainstrength in the vicinity of the fire longer than other materials.

An improved alloy composition may include, by weight: about 18% to about22% chromium, about 5% to about 13% nickel (and in some embodiments,from about 5% to about 9% by weight nickel), about 1% to about 10%copper (and in some embodiments, above 2% to about 6% copper), about 1%to about 10% manganese, about 0.3% to about 1% silicon, about 0.5% toabout 1.5% niobium, about 0.5% to about 2% tungsten, and with thebalance being essentially iron (for example, about 47.8% to about 68.12%iron). The composition may, in some embodiments, include othercomponents, for example, about 0.3% to about 1% molybdenum, about 0.08%to about 0.2% carbon, about 0.2% to about 0.5% nitrogen or mixturesthereof. Other impurities or minor components typically present insteels may also be present. Such an improved alloy may be useful whenprocessed by hot deformation, cold deformation, and/or welding into, forexample, casings, canisters, or strength members for heaters. In someembodiments, the improved alloy includes, by weight: about 20% chromium,about 3% copper, about 4% manganese, about 0.3% molybdenum, about 0.77%niobium, about 13% nickel, about 0.5% silicon, about 1% tungsten, about0.09% carbon, and about 0.26% nitrogen, with the balance beingessentially iron. In certain embodiments, the improved alloy includes,by weight: about 19% chromium, about 4.2% manganese, about 0.3%molybdenum, about 0.8% niobium, about 12.5% nickel, about 0.5% silicon,about 0.09% carbon, about 0.24% nitrogen by weight with the balancebeing essentially iron. In certain embodiments, the improved alloyincludes, by weight: about 21% chromium, about 3% copper, about 8%manganese, about 0.3% molybdenum, about 0.8% niobium, about 7% nickel,about 0.5% silicon, about 1% tungsten, about 0.13% carbon, and about0.37% nitrogen, with the balance being essentially iron. In someembodiments, the improved alloy includes, by weight: about 20% chromium,about 4.4% copper, about 4.5% manganese, about 0.3% molybdenum, about0.8% niobium, about 7% nickel, about 0.5% silicon, about 1% tungsten,about 0.24% carbon, about 0.3% nitrogen by weight with the balance beingessentially iron. In some embodiments, improved alloys may vary anamount of manganese, amount of nickel, a W/Cu ratio, a Mo/W ratio, a C/Nratio, a Mn/N ratio, a Mn/Nb ratio, a Mn/Si ratio and/or a Mn/Ni ratioto enhance resistance to high temperature sulfidation, increase hightemperature strength, and/or reduce cost. For example, for the improvedwrought alloys to have a stable parent austenite phase, high strengthfrom 600° C. to 900° C., and stable nano carbide and nanocarbonitridemicrostructures, the improved wrought alloys may include combinations ofalloying elements present in the improved wrought alloys such that thefollowing ratios (using wt. %) are achieved: a) Mo/W-0.3 to 0.5; b)W/Cu-0.25 to 0.33; c) C/N-0.25 to 0.33; d) Mn/Ni-0.3 to 1.5; e) Mn/N-20to 25; f) Mn/Nb-5 to 13; and g) Mn/Si-4 to 20; and carbon plus nitrogenis from about 0.3 wt % to about 0.6 wt %.

Improved wrought alloy compositions may include the compositionsdescribed in the preceding paragraphs and compositions disclosed in U.S.Pat. No. 7,153,373, which is incorporated herein by reference. Theimproved wrought alloy composition may include at least 3.25% by weightprecipitates at about 800° C. The improved wrought alloy composition mayhave been processed by aging or hot working and/or by cold working. As aresult of such aging or hot working and/or cold working, the improvedwrought alloy compositions (for example, NbC, Cr-rich M₂₃C₆) may containnanocarbonitrides precipitates. Such nanocarbonitride precipitates arenot known to be present in cast compositions such as those disclosed inU.S. Pat. No. 7,153,373, and are believed to form upon hot workingand/or cold working of the compositions. The nanocarbonitrideprecipitates may include particles having dimensions from about 5nanometers to about 100 nanometers, from about 10 nanometers to about 90nanometers, or from about 20 nanometers to about 80 nanometers. Thesewrought alloys may have microstructures that include, but are notlimited to, nanocarbides (for example, NbC, Cr-rich M₂₃C₆), which formduring aging (stress-free) or creep (stress<0.5 yield stress (YS)). Thenanocarbide precipitates may include particles having dimensions from 5nanometers to 100 nanometers, from about 10 nanometers to about 90nanometers, or from about 20 nanometers to about 80 nanometers. Themicrostructures may be a consequence of both the native alloycomposition and the details of the wrought processing. In solutionannealed material, the concentration of such nanoscale particles may below. The nanoscale particles may be affected by solution annealtemperature/time (more and finer dispersion with longer anneal above1150° C.) and by cold- or warm-prestrain (cold work) after the solutionanneal treatment. Cold prestrain may create dislocation networks withinthe grains that may serve as nucleation sites for the nanocarbides.Solution annealed material initially has zero percent cold work.Bending, stretching, coiling, rolling or swaging may create, for exampleabout 5 to about 15% cold work. The effect of the nanocarbides on yieldstrength or creep strength may be to provide strength based ondislocation-pinning, with more closely-spaced pinning sites (higherconcentration, finer dispersion) providing more strength (particles arebarriers to climb or glide of dislocations).

The improved wrought alloy may include nanonitrides (for example,niobium chromium nitrides (NbCrN)) in the matrix together withnanocarbides, after, for example, being aged for 1000 hours at about800° C. The nanonitride precipitates may include particles havingdimensions from about 5 nanometers to about 100 nanometers, from about10 nanometers to about 90 nanometers, or from about 20 nanometers toabout 80 nanometers. Niobium chromium nitrides have been identifiedusing analytical electron microscopy as rich in niobium and chromium,and as the tetragonal nitride phase by electron diffraction (bothcarbides are cubic phases). X-ray energy dispersive quantitativeanalysis has shown that for the improved alloy compositions, thesenanoscale nitride particles may have a composition by weight of: about63% niobium, about 28% chromium, and about 6% iron, with othercomponents being at most 5% each. Such niobium chromium nitrides werenot observed in aged cast stainless steels with similar compositions,and appear to be a direct consequence of the wrought processing.

In some embodiments, the improved wrought alloy may include a mixture ofmicrostructures (for example, a mixture of nanocarbides andnanonitrides). The mixture of microstructures may be responsible for theimproved strength of these alloy compositions at elevated temperatures,such as, for example, about 900-1000° C. In some embodiments, theimproved alloys may have a yield strength greater than 35 kpsi, or 30kpsi at about 800° C.

In some embodiments, the improved alloys are processed to produce awrought material. Processing may include steps such as the following. Acentrifugal cast pipe may be cast from the improved alloy. A section maybe removed from the casting and heat treated at a temperature of atleast 1250° C. for, for example, three hours. The heat treated sectionmay be hot rolled at a temperature of at least 1200° C. to a thicknessof about half of the original thickness inches), annealed at atemperature of at least 1200° C. for fifteen minutes, and thensandblasted. The sandblasted section may be cold rolled to a thicknessof about one third of the original cast thickness. The cold rolledsection may be annealed to a temperature of at least 1250° C. for aperiod of time, for example, an hour, in, for example, air with an argoncover, and then given a final additional heat treatment for one hour ata temperature of at least 1250° C. in air with an argon blanket. Analternative process may include any of the following: initiallyhomogenizing the cast plate at a temperature of at least 1200° C. for aperiod of time, for example 1½ hours; hot rolling at a temperature of atleast 1200° C. to two thirds of the original cast thickness; andannealing the cold-rolled plate for one hour at a temperature of atleast 1200° C. The improved alloys may be extruded at, for example,about 1200° C., with, for example, a mandrel diameter of about 22.9millimeters (0.9 inches) and a die diameter of about 34.3 millimeters(1.35 inches) to produce good quality tubes.

The wrought material may be welded by, for example, laser welding ortungsten gas arc welding. Thus, tubes may be produced by rolling platesand welding seams.

Annealing the improved alloys at higher temperatures, such as about1250° C., may improve properties of the alloys. At a higher temperature,more of the phases go into solution and upon cooling precipitate intophases that contribute positively to the properties, such as hightemperature creep and tensile strength. Annealing at temperatures higherthan 1250° C., such as about 1300° C. may be beneficial. For example,the calculated phase present in the improved alloys may decrease byabout 0.08% at about 1300° C. as opposed to the phase present in theimproved alloys at about 1200° C. Thus, upon cooling, more usefulprecipitates may form by about 0.08%. Improved alloys may have hightemperature creep strengths and tensile strengths that are superior toconventional alloys. For example, niobium stabilized stainless steelalloys that include manganese, nitrogen, copper and tungsten may havehigh temperature creep strengths and tensile strengths that areimproved, or substantially improved relative to conventional alloys suchas 347H.

Improved alloys may have increased strength relative to standardstainless steel alloys such as Super 304H at high temperatures (forexample, about 700° C., about 800° C., or above about 1000° C.).Superior high temperature creep-rupture strength (for example,creep-rupture strength at about 800° C., about 900° C., or about 1250°C.) may be improved as a result of (a) composition, (b) stable,fine-grain microstructures induced by high temperature processing, and(c) age-induced precipitation structures in the improved alloys.Precipitation structures include, for example, microcarbides thatstrengthen grain boundaries and stable nanocarbides that strengtheninside the grains. Presence of phases other than sigma, laves, G, andchi phases contribute to high temperature properties. Stablemicrostructures may be achieved by proper selection of components. Hightemperature aging induced or creep-induced microstructures may haveminimal or no intermetallic sigma, laves and chi phases. Intermetallicsigma, laves and chi phases may weaken the strength properties of alloysand are therefore generally undesirable.

At about 800° C., the improved alloys may include at least 3% or atleast 3.25% by weight of microcarbides, other phases, and/or stable,fine grain microstructure that produce strength. At about 900° C., theimproved alloys may include, by weight, at least 1.5%, at least 2%, atleast 3%, at least 3.5%, or at least 5% microcarbides, other phases,and/or stable, fine grain microstructure that produce strength. Thesevalues may be higher than the corresponding values in 347H or Super 304Hstainless steel alloys at about 900° C. At about 1250° C. improvedalloys may include at least 0.5% by weight microcarbides, other phases,and/or stable, fine grain microstructure that produce strength. Theresulting higher weight percent of microcarbides, other phases, and/orstable, fine grain microstructure, and the exclusion of sigma and lavesphases, may account for superior high temperature performance of theimproved alloys.

Alloys having similar or superior high temperature performance to theimproved alloys may be derived by modeling phase behavior at elevatedtemperatures and selecting compositions that retain at least 1.5%, atleast 2%, or at least 2.5% by weight of phases other than sigma or lavesphases at, for example, about 900° C. For example, a stablemicrostructure may include an amount, by weight, of: niobium that isnearly ten times the amount of carbon, from 1% to 12% manganese, andfrom 0.15 to 0.5% of nitrogen. Copper and tungsten may be included inthe composition to increase the amount of stable microstructures. Thechoice of elements for the improved alloys allows processing by variousmethods and results in a stable, fine grain size, even after heattreatments of at least 1250° C. Many prior art alloys tend to graincoarsen significantly when annealed at such high temperatures whereasthe improved alloy can be improved by such high temperature treatment.In some embodiments, grain size is controlled to achieve desirable hightemperature tensile and creep properties. Stable grain structure in theimproved alloys reduces grain boundary sliding, and may be acontributing factor for the better strength relative to commerciallyavailable alloys at temperatures above, for example, about 650° C.

A downhole heater assembly may include 5, 10, 20, 40, or more heaterscoupled together. For example, a heater assembly may include between 10and 40 heaters. Heaters in a downhole heater assembly may be coupled inseries. In some embodiments, heaters in a heater assembly may be spacedfrom about 8 meters (about 25 feet) to about 60 meters (about 195 feet)apart. For example, heaters in a heater assembly may be spaced about 15meters (about 50 feet) apart. Spacing between heaters in a heaterassembly may be a function of heat transfer from the heaters to theformation. Spacing between heaters may be chosen to limit temperaturevariation along a length of a heater assembly to acceptable limits.Heaters in a heater assembly may include, but are not limited to,electrical heaters, flameless distributed combustors, naturaldistributed combustors, and/or oxidizers. In some embodiments, heatersin a downhole heater assembly may include only oxidizers.

FIG. 146 depicts a schematic of an embodiment of downhole oxidizerassembly 800 including oxidizers 802 connected in series. In someembodiments, oxidizer assembly 800 may include oxidizers 802 andflameless distributed combustors. Oxidizer assembly 800 may be loweredinto an opening in a formation and positioned as desired. In someembodiments, a portion of the opening in the formation may besubstantially parallel to the surface of the Earth. In some embodiments,the opening of the formation may be otherwise angled with respect to thesurface of the Earth. In an embodiment, the opening may include asignificant vertical portion and a portion otherwise angled with respectto the surface of the Earth. In certain embodiments, the opening may bea branched opening. Oxidizer assemblies may branch from common fueland/or oxidant conduits in a central portion of the opening.

Oxidizing fluid 808 may be supplied to oxidizer assembly 800 throughoxidant conduit 810. In some embodiments, fuel conduit 806 and/oroxidizers 802 may be positioned concentrically, or substantiallyconcentrically, in oxidant conduit 810. In some embodiments, fuelconduit 806 and/or oxidizers 802 may be arranged other thanconcentrically with respect to oxidant conduit 810. In certain branchedopening embodiments, fuel conduit 806 and/or oxidant conduit 810 mayhave a weld or coupling to allow placement of oxidizer assemblies 800 inbranches of the opening. Exhaust gas 812 may pass through outer conduit814 and out of the formation.

In some embodiments, the downhole oxidizer assembly includes a waterconduit positioned in the oxidant conduit that is configured to deliverwater to the fuel conduit prior to the first oxidizer in the oxidizerassembly. A portion of the water conduit may pass through a heated zonegenerated by the first oxidizer prior to a water entry point into thefuel conduit. In some embodiments, the fuel conduit is positionedadjacent to the oxidizers, and branches from the fuel conduit providefuel to the other oxidizers. In some embodiments, the fuel conduit maycomprise one or more orifices to selectively control the pressure lossalong the fuel conduit.

Fuel 804 may be supplied to oxidizers 802 through fuel conduit 806. Insome embodiments, the fuel for the oxidizers may be synthesis gas. Insome embodiments, the fuel is synthesis gas (for example, a mixture ofhydrogen and carbon monoxide) that was produced using an in situ heattreatment process. In some embodiments, the fuel contains products froma goal or heavy oil gasification process. The coal or heavy oilgasification process may take place above ground or below ground. Afterinitiation of combustion of fuel and oxidant mixture in oxidizers 802,composition of the fuel may be varied to enhance operational stabilityof the oxidizers.

In certain embodiments, fuel used to initiate combustion may be enrichedto decrease the temperature required for ignition or otherwisefacilitate startup of oxidizers 802. In some embodiments, hydrogen orother hydrogen rich fluids may be used to enrich fuel initially suppliedto the oxidizers. After ignition of the oxidizers, enrichment of thefuel may be stopped. In other embodiments, the fuel may comprise naturalgas mixed with heavier components such as ethane, propane, butane, orcarbon monoxide. In some embodiments, a portion or portions of fuelconduit 806 may include a catalytic surface (for example, a catalyticouter surface) to decrease an ignition temperature of fuel 804.

Coke formation may occur inside the fuel conduit if the fuel containshydrocarbons components and the heat flux is sufficiently high. Afteroxidizer ignition, steps may be taken to reduce coking. For example,steam or water may be added to fuel conduit 806. In some embodiments,coking is inhibited by decreasing a residence time of fuel in fuelconduit 806. The residence time of fuel in fuel conduit 806 maydecreased by varying the size of the fuel conduit. For example, oneportion of fuel conduit 806 may be approximately ¾ inch (approximately1.9 cm) in diameter while another portion may be approximately ⅜ inch(approximately 0.95 cm) in diameter. Alternatively, the thickness andlength of all or portions of fuel conduit 806 may be varied.

In some embodiments, coking is inhibited by insulating portions of fuelconduit 806 that pass through high temperature zones proximate oxidizers802. For example, a portion of fuel conduit 806 may be coated with aninsulating layer and/or a conductive layer. The insulating layer may bemade from thermal insulating materials such as silicon carbide, alumina,mullite, zirconia, and other material known in the art. The conductivelayer may be made from commercially available highly conductivematerials such as ceramics and/or high temperature metals, including butnot limited to Hexyloy (available from Arklay S. Richards Co., Inc.).The insulating layer and/or the conductive layer may be applied to fuelconduit 806 using a high velocity oxygen fuel or air plasma process. Theresulting layer or layers may be heat treated.

In some embodiments, the fuel conduit is treated to remove coke formedin the fuel conduit by decoking. Decoking may be performed throughmechanical means and/or chemical means. For example, coke may be removedfrom the fuel conduit by pumping a metal, studded, foam, or plastic pigthrough the fuel conduit. In an embodiment, a rod is inserted into fuelconduit 806 to dislodge coke particles and push them towards the lastoxidizer in the oxidizer assembly. The rod may be a hydrolance or otherhigh pressure pipe or tube used to direct high pressure water, air,nitrogen, and/or other gas to dislodge the coke.

FIG. 147 and FIG. 148 depict embodiments of oxidizers 802 of oxidizerassemblies positioned in outer conduits 814. Oxidizer 802 may be coupledto fuel conduit 806 that is positioned in oxidant conduit 810. Oxidantand fuel enter mix chamber 818 of oxidizer 802. A combustible mixture offuel and oxidant passes from mix chamber 818 into the space between fuelconduit 806 and shield 824. Shield 824 surrounds a portion of fuelconduit 806. Shield 824 allow development of flame zone 2070 in oxidizer802. Shield 824 inhibits gas flowing in oxidant conduit fromextinguishing flame zone 2070 formed in oxidizer 802. Spacers mayposition oxidizer 802 in oxidant conduit 810. The spacers may be coupledto shield 824 and/or to oxidizer conduit 810. An igniter and/orcombusting fuel in flame zone 2070 oxidizes the mixture of fuel andoxidant in the flame zone.

Insulating layer 2064 may be placed around fuel conduit 806 to at leastpartially surround a portion of the fuel conduit. Insulating layer 2064may be made of a material with low thermal conductivity. Insulatinglayer 2064 may inhibit coking in fuel conduit 806. Insulating layer 2064may only surround portions of fuel conduit 806 that pass throughoxidizers 802. In some embodiments, the insulating layer covers theportion of the fuel conduit passing through the oxidizer and a portionof the fuel conduit before and/or after the oxidizer. In someembodiments, the entire fuel conduit is insulated.

Thermally conductive layer 2066 may surround or partially surroundinsulating layer 2064. Thermally conductive layer 2066 may be locatedadjacent to flame zone 2070. Thermally conductive layer 2066 may spreadthe heat of flame zone 2070 over a large area to help reduce thetemperature applied to insulating layer 2064 below the flame zone. Insome embodiments, the insulating layer does not include a thermallyconductive layer.

FIG. 148 depicts a cross-sectional representation of an embodiment ofoxidizer 802 with gas cooled sleeve 2068. A portion of sleeve 2068 maypass through oxidizer 802 to form an annular space. One or more spacersmay be located between fuel conduit 806 and sleeve 2068 to position thesleeve relative to the fuel conduit. One or more feedthroughs 2072 maydirect fuel from fuel conduit 806 to mix chamber 818 and/or to the areabetween shield 824 and the fuel conduit of oxidizer 802. Some gasflowing in oxidant conduit 810 passes between fuel conduit 806 andinsulating sleeve 2064. Insulating sleeve 2064 may include thermallyconductive layer 2066 to dissipate some of the heat from flame zone 2070over a large area. Gas passing between fuel conduit 806 and insulatingsleeve 2064 may inhibit excessive heating of the fuel conduit adjacentto flame zone 2070.

The flow of fuel in fuel conduit 806 is represented by arrow 2074, andthe flow of gas (for example, air and exhaust products and unburned fuelfrom previous oxidizers) in oxidant conduit 810 is represented by arrow2076. Exhaust gases from all of oxidizers in the oxidizer assembly passthrough outer conduit 814 in the direction indicated by arrow 2078. Flowof gas between fuel conduit 806 and insulating sleeve 2064 may reducethe amount of heat transfer from the insulating sleeve to the fuelconduit. Flame zone 2070 may have a temperature of about 1100° C. (about2000° F.) while the temperature in oxidant conduit adjacent to theshield of oxidizer 802 may be about 700° C. (about 1300° F.).

Oxidant may be supplied through the oxidant conduit to the oxidizers.Oxidizing fluid may include, but is not limited to, air, oxygen enrichedair, and/or hydrogen peroxide. Depletion of oxygen in the oxidant mayoccur toward a terminal end of an oxidizer assembly. In someembodiments, the amount of excess oxidant supplied to the oxidizers isreduced to less than about 50% excess oxidant by weight by controllingthe pressure, temperature, and flow rate of the oxidant in the oxidantconduit. For example, after ignition, the amount of oxidant can bereduced when the temperature of the fuel conduit reaches about 650° C.(about 1200° F.). In some embodiments, the amount of excess oxidant isreduced to less than about 25% excess oxidant by weight. In otherembodiments, the amount of excess oxidant is reduced to less than about10% excess oxidant by weight.

In some embodiments, the amount of excess oxidant is reduced when thetemperature downstream of the oxidizers becomes sufficiently hot tosupport reaction of oxidant and fuel outside of the oxidizers. Oxidantand fuel may react in regions between oxidizers. During such operation,the oxidizer assembly functions much like a flameless distributedcombustor. Generating heat in the regions between the oxidizers mayresult in a smoother temperature profile along the length of theoxidizer assembly. The excess oxidant may be reduced such that the lastoxidizer in the oxidizer assembly substantially eliminates the remainingoxidant in the oxidant conduit. The last oxidizer may be a catalyticoxidizer to minimize or eliminate oxidant remaining in the oxidantconduit.

When the temperature along the length of the oxidizer assembly increasesto a temperature sufficient to support reaction of oxidant with fueloutside of the shields of the oxidizers, the mode of operation of theoxidizer assembly may shift from a series of individual oxidizers withaerodynamically staged flames to a more uniformly distributed or“reactor-stable” mode of operation. During the reactor-stable mode ofoperation, combustion may take place outside the shield along the entirelength of the oxidant conduit. Under this condition stability isachieved by balancing overall heat loss and heat generation over thebroad reaction zone. Local recirculation of hot combustion products toincoming reactants enables minimum reaction temperature wherefuel-oxidant mixtures will oxidize without aerodynamic stabilization. Inthis mode of operation, the oxidizers may still serve as a “safety” ormeans of continuing stabilization, if the temperature falls below thetemperature needed to sustain oxidation of the fuel and oxidant in oneor more regions of the oxidizer. During reactor-stable mode ofoperation, the amount of excess oxygen supplied to the oxidizer assemblymay be reduced. Having the ability to reduce the amount of excess oxygensupplied to the oxidizer assembly may significantly improve the overalleconomics of the system used to heat the formation.

A common problem associated with the operation of gas burners employinga flame mechanism is that at high temperatures, particularly above about1500° C. (about 2730° F.), oxygen and nitrogen present in the aircombine by a thermal formation mechanism to form pollutants such as NOand NO₂, commonly referred to as NOx. By controlling the flow of fueland oxidant and by maintaining a distributed temperature, the formationof NOx may be inhibited. In some embodiments, the flow of fuel andoxidant is controlled to produce less than about 10 parts per million byweight of NOx from the gas burner. The flow of oxidant may be controlledby having openings in shields of the oxidizers sized to bring asufficient flow rate past to the flame zone to dilute the flame withoutcausing the flame to be extinguished. Additionally, water added to thefuel conduit may inhibit NOx formation.

In some embodiments, initiation of the burner assembly is accomplishedby initializing combustion in a specified sequence beginning with thelast oxidizer in the assembly. Referring to FIG. 146, oxidizer assembly800 includes first oxidizer 2080, last oxidizer 2082, and second-to-lastoxidizer 2084. In some embodiments, fuel is supplied through fuelconduit 806, and oxidant is supplied through oxidant conduit 810 toprovide a first combustible mixture to last oxidizer 2082. Combustion isinitiated in last oxidizer 2082 and the supply of oxidant is adjusted tosupply second-to-last oxidizer 2084 with a second combustible mixture.Ignition of last oxidizer 2082 is maintained as second-to-last oxidizer2084 is ignited. Thereafter this process of adjusting the supply ofoxidant to provide a combustible fuel and oxidant mixture to the nextunignited oxidizer and initiating combustion in the unignited oxidizeris repeated until first oxidizer 2080 is ignited. In some embodiments,the fuel pressure is greater than the oxidant pressure at an oxidizerbefore initiating combustion in the oxidizer.

In an embodiment, the start up sequence is optimized by controlling theoxidant and fuel pressure differential along the length of the oxidizerassembly. Because the pressure differential varies over the length ofthe burner assembly, a planned sequential ignition from oxidizer tooxidizer, starting with last (most remote) oxidizer 2082 may beachieved. In this embodiment, the fuel-oxidant mixture in the ignitionregion is optimized at last oxidizer 2082, then at the second to lastoxidizer 2084, and so on, with the fuel-to-oxidant ratio being leastoptimal at first oxidizer 2080. The profiles may be controlled to changethe sequence of ignition. In an embodiment, the profiles may be reversedso that first oxidizer 2080 is ignited first. Altering the profiles maycomprise altering the pressure differential along the oxidizer assemblylength by design of the fuel conduit diameter coupled with optimizationof opening sizes that provide fuel to the oxidizers, of opening sizesthat provide oxidant to the mix chambers of the oxidizers, and ofopenings in the shields that supply oxidant to the flame zone. Inaddition, control may be facilitated by flow restrictions positioned infuel conduit 806.

FIG. 149 depicts a perspective view of an embodiment of oxidizer 802 ofthe downhole oxidizer assembly. Oxidizer 802 may include mix chamber818, igniter holder 820, nozzle and flame holder 822, and shield 824.Fuel conduit 806 may pass through oxidizer 802. Fuel conduit 806 mayhave one or more fuel openings 826 within mix chamber 818 (as shown inFIG. 147). In some embodiments, additional openings in fuel conduit 806allow additional fuel to pass into the space between the fuel conduitand shield 824. Openings 828 allow oxidant to flow into mix chamber 818.Opening 830 allows a portion of the igniter supported on igniter holder820 to pass into oxidizer 802. Shield 824 may include openings 832.Openings 832 may provide additional oxidant to a flame in shield 824.Openings 832 may stabilize the flame in oxidizer 802 and moderate thetemperature of the flame. Spacers 834 may be positioned on shield 824 tokeep oxidizer 802 positioned in oxidant conduit 810.

In some embodiments, flame stabilizers may be added to the oxidizers.The flame stabilizers may attach the flame to the shield. The highbypass flow around the oxidizer cools the shield and protects theinternals of the oxidizer from damage enabling long term operation.FIGS. 150-155 depict various embodiments of shields 824 with flamestabilizers 836. Flame stabilizer 836 depicted in FIG. 150 is a ringsubstantially perpendicular to shield 824. The ring shown in FIG. 151 isangled away from openings 832. The rings may amount to up to about 25%annular area blockage. The rings may establish a recirculation zone nearshield 824 and away from the fuel conduit passing through the center ofthe shield.

FIG. 152 depicts an embodiment of flame stabilizer 836 in shield 824.Flame stabilizer 836 is positioned at an angle over the openings. Flamestabilizer 836 may divert incoming fluid flow through openings 832 in anupstream direction. The diverted incoming fluid may set up a flowcondition somewhat analogous to high swirl recirculation (reverse flow).One or more stagnation zones may develop where a flame front is stable.

FIG. 153 depicts an embodiment of multiple flame stabilizers 836 inshield 824. Shield 824 may have two or more sets of openings 832 alongan axial length of the shield. Rings may be positioned behind one ormore of the sets of openings 832. In some embodiments, adjacent ringsmay cause too much gas flow interference. To inhibit gas flowinterference, 3 partial rings (each ring being about ⅙ thecircumference) may be evenly spaced about the circumference instead ofone complete ring. The next set of 3 partial rings along the axiallength of heat shield may be staggered (for example, the partial ringsmay be rotated by 120° relative to the first set of 3 partial rings).FIG. 154 depicts a cross-sectional representation of shield 824 showingthe last set of openings 832 and the last set of flame stabilizers 836.Shield 824 includes spacers 834. In other embodiments, fewer or morethan 3 partial rings may be used (for example, two partial rings may beused for the first set of openings, and four partial rings may be usedfor the next set of openings). Flame stabilizers 836 may beperpendicular to shield 824, angled towards openings 832, angled awayfrom the openings (as depicted in FIG. 153) or positioned ascombinations of perpendicular and angled orientations.

FIG. 155 depicts an embodiment wherein flame stabilizers 836 aredeflector plates or baffles extending over all or portions of openings832. The portions of flame stabilizers 836 positioned over the openingsmay be cylindrical sections with the concave portions facing openings832. Flame stabilizers 836 may divert incoming fluid flow and allow theflame root area to develop around the deflectors. Some openings in theshield may not include flame stabilizers.

In some embodiments, deflectors may be positioned on the outer surfaceof the shield near to openings in the shield. The deflectors may directsome of the gas flowing through the oxidant conduit through the openingsin the shield.

As depicted in FIGS. 149-155, shield 824 may include opening 832. Thesize and/or number of openings 832 may be varied depending on positionof the oxidizer in the oxidizer assembly to moderate the temperature andensure fuel combustion. In some embodiments, the geometry and size ofopenings 832 on a single oxidizer may be varied to compensate forchanging conditions and needs along the length of the oxidizer.

FIGS. 156-158 depict perspective views of various sectioned oxidizerembodiments. Oxidizers 802 include oxidant openings 828, mix chambers818, nozzle and flame holder 822, and shield 824. FIGS. 156-158 depictvarious positions and sizes for openings 832 in shield 824.

In some embodiments, one or more of the openings in the shield may beangled in a non-perpendicular direction relative to the longitudinalaxis of the shield. Angled openings act as nozzles to alter the entrypath of gas into the shield. Angled openings may promote formation ofinternal low velocity recirculation zones where the reaction front canstabilize and improve the stability and reliability of the oxidizer.

The use of flame stabilizers, various sizes of openings in the shieldand/or angled openings may establish the flame zone of the oxidizerclose to the shield and as far away from the fuel conduit to maximizeradial separation of the flame zone from the fuel conduit to minimizedirect heating of the fuel conduit by the flame zone. The use of flamestabilizers, various sizes of openings in the shield and/or angledopenings may also achieve lower NOx emissions by effectivelyaerodynamically staging the combustion zone and creating fuel rich andlean zones. In fuel rich zones, N₂ formation (instead of NOx) will befavored and aerodynamic staging will control peak temperatures andthermal NOx formation. Such configurations can also enable control ofthe peak longitudinal temperature profile and flame radiation, hencesuppressing overheating of the fuel conduit.

The oxidizers may include shields which utilize a louvered design todirect flow into the shield. FIG. 159 depicts oxidizer 802 with louveredopenings 832 in shield 824. Louvered openings 832 are in communicationwith the oxidant conduit and are configured to direct flow into shield824 in a direction opposite to the direction of flow in the oxidantconduit. FIG. 160 depicts a cross-sectional representation of a portionof shield 824 with louvered opening 832. Gas with oxidant may bedirected from oxidant conduit to the inside of shield 824. Arrow 2086indicates the direction of gas flow from the oxidant conduit to theinside of shield. Arrow 2088 indicates the direction of gas flow in theoxidant conduit.

In some embodiments, fuel passes through a heated region before beingsupplied to the first oxidizer (oxidizer 2080 in FIG. 146). Passing thefuel through the heated region may preheat the fuel and ensure that thefuel and additives in the fuel (for example, water to inhibit coking)are in the gas phase. Ensuring gas phase fuel may avoid plugging infirst oxidizer 2080. FIG. 161 depicts an embodiment of first oxidizer2080 and fuel conduit 806. Fuel conduit 806 may include sleeve 2090.Fuel may flow through sleeve, and a portion of the fuel may flow in theopposite direction in the annular space between the sleeve and fuelconduit 806. A portion of the fuel flowing in the annular space betweensleeve 2090 and fuel conduit 806 passes through openings 826 into mixchamber 818.

In some embodiments, a portion of the fuel flowing in the annular spacebetween sleeve 2090 and fuel conduit 806 passes through openings 826into the annular space between the fuel conduit and shield 824.Supplying fuel into this annular space may allow flame zone 2070 toextend through a significant portion of first oxidizer 2080 so that thefirst oxidizer is able to input more heat into the formation. Firstoxidizer 2080 may be configured to input more heat into the formation tohelp compensate for heat losses attributable to the oxidizer being thefirst oxidizer of the oxidizer assembly. Having first oxidizerconfigured to input more heat into the formation than other oxidizers ofthe oxidizer assembly may allow for a decrease in the total number ofoxidizers needed in the downhole assembly.

One or more of the oxidizers in an oxidizer assembly may be a catalyticburner. The catalytic burners may include a catalytic portion (forexample, catalyst chamber) followed by a homogenous portion (forexample, mix chamber). Catalytic burners may be started late in anignition sequence, and may ignite without igniters. Oxidant for thecatalytic burners may be sufficiently hot from upstream burners (forexample, the oxidant may be at a temperature of about 370° F. (about700° C.) if the fuel is primarily methane) so that a primary mixturewould react over the catalyst in the catalyst portion and produce enoughheat so that exiting products ignite a secondary mixture in thehomogenous portion of the oxidizer. In some embodiments, the fuel mayinclude enough hydrogen to allow the needed temperature of the oxidantto be lower. Catalysts used for this purpose may include palladium,platinum, platinum/iridium, and platinum/rhodium.

FIG. 162 depicts a cross-sectional representation of catalytic burner838. Oxidizer may enter mix chamber 818 through openings 828. Fuel mayenter mix chamber 818 from fuel conduit 806 through fuel openings 826′.Fuel and oxidizer may flow to catalyst chamber 840. Catalyst chamber 840contains catalyst which reacts a mixture from mix chamber 818 to producereaction products at a temperature that is sufficient to ignite fuel andoxidant. In some embodiments, the catalyst includes palladium on ahoneycomb ceramic support. The fuel and oxidant react in catalystchamber 840 to form hot reaction products. The hot reaction products maybe directed to the annular space between shield 824 and fuel conduit806. Additional fuel enters the annular space through openings 826″ infuel conduit 806. Additional oxidant enters the annular space throughopenings 832. The hot reaction products generated by catalyst 840 mayignite fuel and oxidant in autoignition zone 842. Autoignition zone 842may allow fuel and oxidant to form flame zone 2070. In some embodiments,the catalytic burner includes flame stabilizers or other types of gasflow modifiers.

In some embodiments a catalytic burner may include an igniter tosimplify startup procedures. FIG. 163 depicts catalytic burner 838 thatincludes igniter 816. Igniter 816 is positioned in mix chamber 818.Catalytic burner 838 includes catalyst chamber 840. Catalyst chambercontains a catalyst that reacts a mixture from mix chamber 818 toproduce reaction products at a temperature that is sufficient to ignitefuel and oxidant. Oxidant enters mix chamber through openings 828A. Fuelenters the mix chamber from fuel line through fuel openings 826A. Thefuel input into mixture chamber 818 may be only a small fraction of thefuel input for catalytic burner 838. Igniter 816 raises the temperatureof the fuel and oxidant to combustion temperatures in pre-heat zone 846.Flame stabilizer 836 may be positioned in mixing chamber 818. Heat frompre-heat zone 846 and/or combustion products may heat additional fuelthat enters mixing chamber 818 through fuel openings 826B and additionaloxidant that enters the mixing chamber through openings 828B. Openings826B and openings 828B may be upstream of flame stabilizer 836. Theadditional fuel and oxidant are heated to a temperature sufficient tosupport reaction on catalyst 840.

Heated fuel and oxidant from mixing chamber 818 pass to catalyst 840.The fuel and oxidant react on catalyst 840 to form hot reactionproducts. The hot reaction products may be directed to heat shield 824.Additional fuel enters heat shield 824 through openings 826C in fuelconduit 806. Additional oxidant enters heat shield 824 through openings832. The hot reaction products generated by catalyst 840 may ignite fueland oxidant in autoignition zone 842. Autoignition zone 842 may allowfuel and oxidant to form main combustion zone 2070. In some embodiments,the catalytic burner includes flame stabilizers or other types of gasflow modifiers.

In some embodiments, all of the oxidizers in the oxidizer assembly arecatalytic burners. In some embodiments, the first or the first severaloxidizers in the oxidizer assembly are catalytic burners. The oxidantsupplied to these burners may be at a lower temperature than subsequentburners. Using catalytic burners with igniters may stabilize theperformance of the first several oxidizers in the oxidizer assembly.Catalytic burners may be used in-line with other burners to reduceemissions by allowing lower flame temperatures while still havingsubstantially complete combustion.

In some embodiments, a catalytic converter may be positioned at the endof the oxidizer assembly or in the exhaust gas return. The catalyticconverter may remove unburned hydrocarbons and/or remaining NOxcompounds or other pollutants. The catalytic converter may benefit fromthe relatively high temperature of the exhaust gas. In some embodiments,catalytic burners in series may be integrated with coupled catalyticconverters to limit undesired emissions from the oxidizer assembly. Insome embodiments, a selectively permeable material may be used to allowcarbon dioxide or other fluids to be separated from the exhaust gas.

In one embodiment, initiation of the burner assembly may be accomplishedby initializing combustion with hydrogen and later switching to naturalgas or another fuel. The use of hydrogen-enriched fuel may suppressflame radiation and reduce heating of the fuel conduit. Oxidizers of theoxidizer assembly may be ignited using hydrogen or fuel that is highlyenriched with hydrogen. Once ignited, the composition of fuel may beadjusted to comprise natural gas and/or other fuels. The initial use ofhydrogen or hydrogen-enriched fuel widens the flammability envelopeenabling much easier startup. An initial fuel composition could then be“chased” with production gas or other more economical gases.Alternatively, the entire system could burn hydrogen. With no carbon inthe fuel, there would be no need for additional decoking methods.

In some embodiments, pulverized coal is the fuel used to heat thesubsurface formation. The pulverized coal may be carried into thewellbores with a non-oxidizing fluid (for example, carbon dioxide and/ornitrogen). An oxidant may be mixed with the pulverized coal at severallocations in the wellbore. The oxidant may be air, oxygen enriched airand/or other types of oxidizing fluids. Igniters located at or near themixing locations initiate oxidation of the coal and oxidant. Theigniters may be catalytic igniters, glow plugs, spark plugs, and/orelectrical heaters (for example, an insulated conductor temperaturelimited heater with heating sections located at mixing locations ofpulverized coal and oxidant) that are able to initiate oxidation of theoxidant with the pulverized coal. In FIG. 146, pulverized coal entrainedin a carrier fluid may be fuel 804 supplied to oxidizers 802 throughfuel conduit 806. Initially, oxidizer assembly 800 may be started usinghydrogen, natural gas, or other fuel. After temperatures of oxidizers802 are hot enough to support rapid pulverized coal oxidation (forexample, the temperature in and adjacent to the oxidizers is above about600° C.), the fuel may be changed to pulverized coal and carrier gas.

The particles of the pulverized coal may be small enough to pass throughflow orifices and achieve rapid combustion in the oxidant. Thepulverized coal may have a particle size distribution from about 1micron to about 300 microns, from about 5 microns to about 150 microns,or from about 10 microns to about 100 microns. Other pulverized coalparticle size distributions may also be used. At 600° C., the time toburn the volatiles in pulverized coal with a particle size distributionfrom about 10 microns to about 100 microns may be about one second.

When using coal as the fuel for downhole oxidizers, exhaust gases fromthe heater wells may be treated to remove unreacted coal, ash, finesand/or other particles in the exhaust gas. In some embodiments, theexhaust gas passes through one or more cyclones to remove particles fromthe exhaust gas. The exhaust gas may be further processed to removeselected compounds (for example, sulfur and/or nitrogen compounds), maybe used as a drive fluid for mobilizing hydrocarbons in a formation, maybe sequestered in a subsurface formation, and/or may be otherwisehandled.

In other embodiments, other types of downhole oxidizers are used for thesubsurface oxidation of coal to heat selected portions of the formation.FIG. 164 depicts a schematic representation of heater 2092 that usespulverized coal as fuel. Heater 2092 may include outer conduit 814,first conduit 2094, and second conduit 2096. First conduit 2094 ispositioned in outer conduit 814, and second conduit 2096 is positionedin the first conduit. The end of second conduit may be closed. Secondconduit 2096 may include critical flow orifices 2098. The flow rateand/or pressures of the fluids flowing through first conduit 2094 andsecond conduit 2096 may be controlled to allow for mixing of fluid fromthe first conduit with fluid from the second conduit at desiredlocations in the first conduit.

In an embodiment, coal and carrier gas is introduced into heater 2092through first conduit 2094, and oxidant is introduced through secondconduit 2096. The flow rate and/or pressure in first conduit 2094 andsecond conduit 2096 are controlled so that the oxidant flows throughcritical flow orifices 2098 into the coal and carrier gas flowingthrough first conduit 2094. Reaction of the coal and oxidant occurs infirst conduit 2094. Exhaust gases pass through outer conduit 814 to thesurface. Passing the exhaust gases past the locations where oxidant andcoal are oxidized may reduce temperature variations along the length ofthe heated section of heater 2092.

In an embodiment, oxidant is introduced into heater 2092 through firstconduit 2094, and coal and carrier gas is introduced through secondconduit 2096. The flow rate and/or pressure of in first conduit 2094 andsecond conduit 2096 are controlled so that the coal and carrier gasflows through critical flow orifices 2098 into the oxidant flowingthrough first conduit 2094. Reaction of the coal and oxidant occurs infirst conduit 2094. Exhaust gases pass through outer conduit 814 to thesurface.

FIG. 165 depicts a schematic representation of heater 2092 that usespulverized coal as fuel. Heater 2092 may include outer conduit 814,first conduit 2094, and second conduit 2096. First conduit 2094 ispositioned in outer conduit 814, and second conduit 2096 is positionedin the first conduit. The end of first conduit 2094 may be sealed closedagainst second conduit 2096. Second conduit 2096 may include criticalflow orifices 2098. The flow rate and/or pressures of the fluids flowingthrough first conduit 2094 and second conduit 2096 may be controlled toallow for mixing of fluid from the first conduit with fluid from thesecond conduit at desired locations in the second conduit.

In an embodiment, oxidant is introduced into heater 2092 through firstconduit 2094, and coal and carrier gas is introduced through secondconduit 2096. The flow rate and/or pressure of in first conduit 2094 andsecond conduit 2096 are controlled so that the oxidant flows throughcritical flow orifices 2098 into the coal and carrier gas flowingthrough second conduit 2096. Reaction of the coal and oxidant occurs insecond conduit 2096. Reacting coal and oxidant in second conduit 2096and passing exhaust gases pass through outer conduit 814 to the surfacemay reduce the formation of hot zones adjacent to sections of heater2092 where oxidation occurs.

In an embodiment, coal and carrier gas is introduced into heater 2092through first conduit 2094, and oxidant is introduced through secondconduit 2096. The flow rate and/or pressure in first conduit 2094 andsecond conduit 2096 are controlled so that the coal and carrier gasflows through critical flow orifices 2098 into oxidant flowing throughsecond conduit 2096. Reaction of the coal and oxidant occurs in secondconduit 2096. Exhaust gases pass through outer conduit 814 to thesurface.

In some in situ heat treatment process embodiments, a circulation systemis used to heat the formation. The circulation system may be a closedloop circulation system. FIG. 166 depicts a schematic representation ofa system for heating a formation using a circulation system. The systemmay be used to heat hydrocarbons that are relatively deep in the groundand that are in formations that are relatively large in extent. In someembodiments, the hydrocarbons may be 100 m, 200 m, 300 m or more belowthe surface. The circulation system may also be used to heathydrocarbons that are not as deep in the ground. The hydrocarbons may bein formations that extend lengthwise up to 500 m, 750 m, 1000 m, ormore. The circulation system may become economically viable informations where the length of the hydrocarbon containing formation tobe treated is long compared to the thickness of the overburden. Theratio of the hydrocarbon formation extent to be heated by heaters to theoverburden thickness may be at least 3, at least 5, or at least 10. Theheaters of the circulation system may be positioned relative to adjacentheaters so that superposition of heat between heaters of the circulationsystem allows the temperature of the formation to be raised at leastabove the boiling point of aqueous formation fluid in the formation.

In some embodiments, heaters 760 may be formed in the formation bydrilling a first wellbore and then drilling a second wellbore thatconnects with the first wellbore. Piping may be positioned in theU-shaped wellbore to form U-shaped heater 760. Heaters 760 are connectedto heat transfer fluid circulation system 868 by piping. Gas at highpressure may be used as the heat transfer fluid in the closed loopcirculation system. In some embodiments, the heat transfer fluid iscarbon dioxide. Carbon dioxide is chemically stable at the requiredtemperatures and pressures and has a relatively high molecular weightthat results in a high volumetric heat capacity. Other fluids such assteam, air, helium and/or nitrogen may also be used. The pressure of theheat transfer fluid entering the formation may be 3000 kPa or higher.The use of high pressure heat transfer fluid allows the heat transferfluid to have a greater density, and therefore a greater capacity totransfer heat. Also, the pressure drop across the heaters is less for asystem where the heat transfer fluid enters the heaters at a firstpressure for a given mass flow rate than when the heat transfer fluidenters the heaters at a second pressure at the same mass flow rate whenthe first pressure is greater than the second pressure. In someembodiments, a liquid heat transfer fluid may be used. The liquid heattransfer fluid may be a natural or synthetic oil, or other type of hightemperature heat transfer fluid.

Heat transfer fluid circulation system 868 may include heat supply 870,first heat exchanger 872, second heat exchanger 874, and compressor 876.Heat supply 870 heats the heat transfer fluid to a high temperature.Heat supply 870 may be a furnace, solar collector, chemical reactor,nuclear reactor, fuel cell exhaust heat, or other high temperaturesource able to supply heat to the heat transfer fluid. In the embodimentdepicted in FIG. 166, heat supply 870 is a furnace that heats the heattransfer fluid to a temperature in a range from about 700° C. to about920° C., from about 770° C. to about 870° C., or from about 800° C. toabout 850° C. In an embodiment, heat supply 870 heats the heat transferfluid to a temperature of about 820° C. The heat transfer fluid flowsfrom heat supply 870 to heaters 760. Heat transfers from heaters 760 toformation 758 adjacent to the heaters. The temperature of the heattransfer fluid exiting formation 758 may be in a range from about 350°C. to about 580° C., from about 400° C. to about 530° C., or from about450° C. to about 500° C. In an embodiment, the temperature of the heattransfer fluid exiting formation 758 is about 480° C. The metallurgy ofthe piping used to form heat transfer fluid circulation system 868 maybe varied to significantly reduce costs of the piping. High temperaturesteel may be used from heat supply 870 to a point where the temperatureis sufficiently low so that less expensive steel can be used from thatpoint to first heat exchanger 872. Several different steel grades may beused to form the piping of heat transfer fluid circulation system 868.

Heat transfer fluid from heat supply 870 of heat transfer fluidcirculation system 868 passes through overburden 458 of formation 758 tohydrocarbon layer 460. Portions of heaters 760 extending throughoverburden 458 may be insulated. In some embodiments, the insulation orpart of the insulation is a polyimide insulating material. Inletportions of heaters 760 in hydrocarbon layer 460 may have taperinginsulation to reduce overheating of the hydrocarbon layer near the inletof the heater into the hydrocarbon layer.

In some embodiments, the diameter of the pipe in overburden 458 may besmaller than the diameter of pipe through hydrocarbon layer 460. Thesmaller diameter pipe through overburden 458 may allow for less heattransfer to the overburden. Reducing the amount of heat transfer tooverburden 458 reduces the amount of cooling of the heat transfer fluidsupplied to pipe adjacent to hydrocarbon layer 460. The increased heattransfer in the smaller diameter pipe due to increased velocity of heattransfer fluid through the small diameter pipe is offset by the smallersurface area of the smaller diameter pipe and the decrease in residencetime of the heat transfer fluid in the smaller diameter pipe.

After exiting formation 758, the heat transfer fluid passes throughfirst heat exchanger 872 and second heat exchanger 874 to compressor876. First heat exchanger 872 transfers heat between heat transfer fluidexiting formation 758 and heat transfer fluid exiting compressor 876 toraise the temperature of the heat transfer fluid that enters heat supply870 and reduce the temperature of the fluid exiting formation 758.Second heat exchanger 874 further reduces the temperature of the heattransfer fluid before the heat transfer fluid enters compressor 876.

FIG. 167 depicts a plan view of an embodiment of wellbore openings inthe formation that is to be heated using the circulation system. Heattransfer fluid entries 878 into formation 758 alternate with heattransfer fluid exits 880. Alternating heat transfer fluid entries 878with heat transfer fluid exits 880 may allow for more uniform heating ofthe hydrocarbons in formation 758.

In some embodiments, piping for the circulation system may allow thedirection of heat transfer fluid flow through the formation to bechanged. Changing the direction of heat transfer fluid flow through theformation allows each end of a u-shaped wellbore to initially receivethe heat transfer fluid at the heat transfer fluid's hottest temperaturefor a period of time, which may result in more uniform heating of theformation. The direction of heat transfer fluid may be changed atdesired time intervals. The desired time interval may be about a year,about six months, about three months, about two months or any otherdesired time interval.

In some embodiments, nuclear energy may be used to heat the heattransfer fluid used in the circulation system to heat a portion of theformation. Heat supply 870 in FIG. 166 may be a pebble bed reactor orother type of nuclear reactor, such as a light water reactor. The use ofnuclear energy provides a heat source with no carbon dioxide emissions.Also, the use of nuclear energy can be more efficient because energylosses resulting from the conversion of heat to electricity andelectricity to heat are avoided by directly utilizing the heat producedfrom the nuclear reactions without producing electricity.

In some embodiments, a nuclear reactor may heat helium. For example,helium flows through a pebble bed reactor, and heat transfers to thehelium. The helium may be used as the heat transfer fluid to heat theformation. In some embodiments, the nuclear reactor may heat helium, andthe helium may be passed through a heat exchanger to provide heat to theheat transfer fluid used to heat the formation. The pebble bed reactormay include a pressure vessel that contains encapsulated enricheduranium dioxide fuel. Helium may be used as a heat transfer fluid toremove heat from the pebble bed reactor. Heat may be transferred in aheat exchanger from the helium to the heat transfer fluid used in thecirculation system. The heat transfer fluid used in the circulationsystem may be carbon dioxide, a molten salt, or other fluid. Pebble bedreactor systems are available from PBMR Ltd (Centurion, South Africa).

FIG. 168 depicts a schematic diagram of a system that uses nuclearenergy to heat treatment area 882. The system may include helium systemgas blower 884, nuclear reactor 886, heat exchanger units 888, and heattransfer fluid blower 890. Helium system gas blower 884 may draw heatedhelium from nuclear reactor 886 to heat exchanger units 888. Helium fromheat exchanger units 888 may pass through helium system gas blower 884to nuclear reactor 886. Helium from nuclear reactor 886 may be at atemperature of about 900° C. to about 1000° C. Helium from helium gasblower 884 may be at a temperature of about 500° C. to about 600° C.Heat transfer fluid blower 890 may draw heat transfer fluid from heatexchanger units 888 through treatment area 882. Heat transfer fluid maypass through heat transfer fluid blower 890 to heat exchanger units 888.The heat transfer fluid may be carbon dioxide. The heat transfer fluidmay be at a temperature from about 850° C. to about 950° C. afterexiting heat exchanger units 888.

In some embodiments, the system may include auxiliary power unit 900. Insome embodiments, auxiliary power unit 900 generates power by passingthe helium from heat exchanger units 888 through a generator to makeelectricity. The helium may be sent to one or more compressors and/orheat exchangers to adjust the pressure and temperature of the heliumbefore the helium is sent to nuclear reactor 886. In some embodiments,auxiliary power unit 900 generates power using a heat transfer fluid(for example, ammonia or aqua ammonia). Helium from heat exchanger units888 is sent to additional heat exchanger units to transfer heat to theheat transfer fluid. The heat transfer fluid is taken through a powercycle (such as a Kalina cycle) to generate electricity. In anembodiment, nuclear reactor 886 is a 400 MW reactor and auxiliary powerunit 900 generates about 30 MW of electricity.

FIG. 169 depicts a schematic elevational view of an arrangement for anin situ heat treatment process. U-shaped wellbores may be formed in theformation to define treatment areas 882A, 882B, 882C, 882D. Additionaltreatment areas could be formed to the sides of the shown treatmentareas. Treatment areas 882A, 882B, 882C, 882D may have widths of over300 m, 500 m, 1000 m, or 1500 m. Well exits and entrances for thewellbores may be formed in well openings area 902. Rail lines 904 may beformed along sides of treatment areas 882. Warehouses, administrationoffices and/or spent fuel storage facilities may be located near ends ofrail lines 904. Facilities 906 may be formed at intervals along spurs ofrail lines 904. Each facility 906 may include a nuclear reactor,compressors, heat exchanger units and other equipment needed forcirculating hot heat transfer fluid to the wellbores. Facilities 906 mayalso include surface facilities for treating formation fluid producedfrom the formation. In some embodiments, heat transfer fluid produced infacility 906′ may be reheated by the reactor in facility 906″ afterpassing through treatment area 882A. In some embodiments, each facility906 is used to provide hot treatment fluid to wells in one half of thetreatment area 882 adjacent to the facility. Facilities 906 may be movedby rail to another facility site after production from a treatment areais completed.

In some embodiments, nuclear energy may be used to directly heat aportion of the subsurface formation. The portion of the subsurfaceformation may be part of the hydrocarbon treatment area. As opposed tousing a nuclear reactor facility to heat a heat transfer fluid, which isthen provided to the subsurface formation to heat the subsurfaceformation, one or more self-limiting nuclear heaters may be positionedunderground to directly heat the subsurface formation.

In some embodiments, a nuclear heater assembly may include one or moreencapsulated nuclear material elements (nuclear pebble heaters)positioned in the subsurface formation. In some embodiments, theencapsulated nuclear material elements are commercially availablespheres that include fissionable material encapsulated in carbon. Thenuclear pebble heaters are typically used in pebble bed reactors.Nuclear pebble heaters may be positioned in a fuel conduit within thesubsurface formation. Nuclear pebble heaters may be positioned in thefuel conduit before and/or after the fuel conduit is positioned in thesubsurface formation.

FIG. 170 depicts an embodiment of U-shaped nuclear heater assembly 2192.FIG. 171 depicts nuclear heater assembly 2192 positioned in a wellborewhere only one end of the wellbore extends to the surface. Nuclearheater assembly 2192 may include outer conduit 2194. Fuel conduit 2196may be positioned in outer conduit 2194. Nuclear heater assembly 2192may include one or more nuclear pebble heaters 2198. Nuclear pebbleheaters 2198, nuclear modulators 2202, and/or nuclear reflectors 2200may be positioned in fuel conduit 2196. Heat transfer fluid 2206 may becirculated past nuclear pebble heaters 2198. Heat transfer fluid 2206may be circulated between the outer surface of fuel conduit 2196 and theinner surface of outer conduit 2194. Heat transfer fluid may be sealedinside fuel conduit 2196. Heat transfer fluid 2206 may distribute heatalong the length of nuclear heater assembly 2192. In some embodiments,heat transfer fluid 2206 is helium gas. Nuclear pebble heaters 2198 maybe circulated by heat transfer fluid 2206. Circulation of nuclear pebbleheaters 2198 may maintain activation of the nuclear pebble heaters. Heattransfer fluid 2206 may push and/or carry nuclear pebble heaters,nuclear moderators, and/or nuclear reflectors to the surface of thewellbore.

In certain embodiments, fuel conduit 2196 is formed from a material thathas high neutron reflectivity. Neutron reflective material mayfacilitate continuation of the nuclear reactions occurring in nuclearpebble heaters 2198 by reflecting neutrons that escape the nuclearpebble heaters back towards the originating nuclear pebble heaters orother nuclear pebble heaters positioned in fuel conduit 2196. Neutronreflective material may inhibit neutrons from escaping fuel conduit 2196into the surrounding subsurface formation. Formation of radioactiveisotopes in the subsurface formation adjacent to nuclear heater assembly2192 may be limited and/or inhibited by surrounding nuclear pebbleheaters 2198 with one or more conduits made out of neutron reflectivematerial (for example, fuel conduit 2196 and outer conduit 2194).

An example of a neutron reflective material suitable for encasingnuclear pebble materials is iron. In certain embodiments, it may beimportant to ensure the iron used is relatively pure and avoid somecommon impurities and/or additives typically combined with iron (such aschromium used in stainless steel). Other elements that may be avoided ina fuel conduit include, but are not limited to, nickel, manganese andcobalt. Additional reflection of thermal neutrons from the carbon andhydrogen atoms in the hydrocarbon containing formation may increase thethermal neutron flux experienced by the nuclear pebble heaters.

In some embodiments, nuclear heater assembly 2192 includes outer conduit2194. Fuel conduit 2196 may be positioned in outer conduit 2194 beforeand/or after the outer conduit has been positioned in the subsurfaceformation. In some embodiments, the nuclear heater assembly may bepositioned in a casing in the sub surface formation. The casing may becemented in the formation using a graphite based cement (for example 65%by weight graphite based cement). Graphite based cement may assist inmaintaining application of a high thermal neutron flux to the nuclearpebble heaters. In certain embodiments, outer conduit 2194 includesmaterial that is complementary to the material in fuel conduit 2196. Forexample, fuel conduit 2196 may reflect neutrons but not be resistant tocorrosion from fluids in the formation. Thus, outer conduit 2194 may beformed of a corrosion resistant material that may protect the fuelconduit from corrosive elements. In certain embodiments, outer conduit2194 is formed from a corrosion resistant material such as stainlesssteel. In some embodiments, outer conduit 2194 is a composite iron orcarbide and stainless steel (for example, an inside surface of outerconduit 2194 may be thick iron conduit and the outer surface of theouter conduit is stainless steel).

Commercially available nuclear pebble heater designs typically includelow level enriched uranium triple-coated isotropic particles containedin a molded graphite sphere. A coated particle may include a kernel ofuranium dioxide surrounded by four coating layers.

During the nuclear pebble heater fabrication process, a solution ofuranyl nitrate is sprayed to form microspheres. The microspheres maythen be gelled and calcined (baked at high temperature) to produceuranium dioxide fuel “kernels”. The kernels are then run through achemical vapor deposition oven. The chemical vapor deposition oventypically uses an argon environment at a temperature of about 1000° C.,and layers of specific chemicals are added with precision.

The first layer deposited on the kernels may be porous carbon, allowingfission products to collect without over-pressurizing the coated fuelparticles. A second layer may include a thin coating of pyrolyticcarbon. Pyrolytic carbon is a very dense form of heat-treated carbon.Following the second layer, a third layer of silicon carbide may beapplied. The silicon carbide may function as a refractory material.Following the third layer, a fourth layer of pyrolytic carbon may beapplied.

The porous carbon may accommodate any mechanical deformation that theuranium dioxide kernel may undergo during the lifetime of the nuclearpebble heater as well as accommodating gaseous fission productsdiffusing out of the kernel. The pyrolytic carbon and silicon carbidelayers provide a barrier designed to contain the fuel and radioactivefission products resulting from nuclear reactions in the kernel.

In a typical nuclear pebble heater, about 15,000 coated particles aremixed with graphite powder and a phenolic resin and pressed into aspherical shape. The coated particles are about a millimeter indiameter. The resulting sphere is about 50 mm in diameter. A 5 mm thicklayer of pure carbon may be added to form a “non-fuel” zone. Theresulting spheres may be sintered and annealed to make them hard anddurable. The spherical nuclear pebble heater may be machined to auniform diameter of about 60 mm. Each nuclear pebble heater may includea total of about 9 g of uranium. In other embodiments, the size, numberand composition of layers, and/or the amount of fissionable material maybe different.

To have a self-sustaining reaction in the nuclear pebble heaters, theuranium in the nuclear pebble heaters may be enriched to include about9% uranium-235, which is the isotope of uranium that undergoes fissionin the nuclear pebble heaters. Uranium-235 occurs in natural uranium ata concentration of about 0.7%.

In some embodiments, nuclear pebble heaters 2198 are acquired new (forexample, right after production and before they have been used in anuclear reactor). Nuclear pebble heaters 2198 are currently produced foruse in pebble bed reactors. Nuclear pebble heaters 2198 enriched with 9%uranium-235 may, in some embodiments, be too powerful, produce too muchheat, and/or produce heat for too long a time. For example, currentcommercially produced nuclear pebble heaters have about 9 g of uranium,which equates to a heat production of about 950 watts per pebble. Insome embodiments, nuclear heater assembly 2192 requires about 300 wattsof energy per foot. Therefore, filling a majority of fuel conduit 2196with nuclear pebble heaters 2198 capable of producing 950 watts each mayproduce more heat than necessary to heat the subsurface formation to adesired temperature. In certain embodiments, however, methods or stepsmay be taken to produce desired energy outputs per foot in nuclearheater assembly 2192.

In some embodiments, treatment of the subsurface formation requiresheating the formation to a desired initial upper range (for example,from about 250° C. to about 350° C.). After heating the subsurfaceformation to the desired temperature range, the temperature may bemaintained in the range for a desired time (for example, until apercentage of hydrocarbons have been pyrolyzed or an average temperaturein the formation reaches a selected value). As the formation temperaturerises, the heater temperature may be slowly lowered over a period oftime. Currently, activated nuclear pebble heaters reach a natural heatoutput limit that results in a maximum temperature of the nuclear pebbleheaters of about 900° C. As the uranium-235 fuel in the nuclear pebbleheaters is depleted, the maximum heat output available from the nuclearpebble heaters decreases. The natural energy output curve of nuclearpebble heaters may be used to provide a desired heating versus timeprofile for certain subsurface formations.

Placing the nuclear pebble heaters in a hydrocarbon-rich zone may bedesirable. The nuclear pebble heaters may be designed to provide amaximum heat output equivalent to the heat losses into the formation.

The nuclear pebble heaters have a temperature self-limiting effect dueto Doppler broadening. Doppler broadening is the broadening of spectrallines due to the Doppler effect. The Doppler effect is described as thethermal movement of atoms or molecules and how that thermal movementshifts the apparent frequency of each emitter. The many differentvelocities of the thermal neutrons result in many small shifts, thecumulative effect of which is to broaden the line. The resulting lineprofile is known as a Doppler profile. The broadening may be dependentonly on the wavelength of the line, the mass of the emitting particle,and the temperature. As the of the nuclear pebble heater temperatureincreases, more thermal neutrons are absorbed by the uranium-238 atomsin the nuclear pebble heater, so less are available for fissioning theremaining uranium-235. In nuclear pebble heaters, the Doppler broadeningeffect reduces the power generated as the temperature of the nuclearpebble heaters increases.

When the nuclear pebble heater gets hotter, the accelerated motion ofthe atoms in the fuel increases the probability of neutron capture byuranium-238 atoms present in the nuclear pebble heater. Uranium-238,which typically forms the bulk of the uranium in the reactor, is muchmore likely to absorb fast neutrons. The neutrons absorbed by theuranium-238 reduces the number of neutrons available to cause remaininguranium-235 fission, thus reducing the power output by the nuclearpebble heater. This natural negative feedback limits the temperaturethat the individual nuclear pebble heaters can obtain.

As depicted in FIGS. 170-176, nuclear heater assembly 2192 includes oneor more neutron reflectors 2200 and/or neutron moderators 2202. Neutronmoderators 2202 slow fast neutrons to thermal velocities that increasethe likelihood of the neutrons to cause fission of uranium-235 nuclei.Nuclear heater assembly 2192 may include one or more spacers 2204 thatare not involved in the nuclear process. Spacers 2204 may providespacing between nuclear pebble heaters 2198 to control the amount ofheat output per unit length provided by nuclear heater assembly 2192.Spacers may be made of alumina, silica or other material. Neutronreflectors 2200 and/or moderators 2202 may be positioned in fuel conduit2196. Neutron moderators 2202 may be required to maintain sufficientthermal neutron flux of nuclear pebble heaters 2198 to sustain thefission reactions that produce heat.

Neutron reflectors 2200 may be formed from neutron reflective material.In some embodiments, neutron reflectors are formed from a similarmaterial as is used to form fuel conduit 2196. For example, may beformed from iron, beryllium, tungsten carbide, graphite, or mixturesthereof. Neutron moderators may be formed from graphite. Neutronreflectors and/or neutron moderators may be solid or hollow. Hollowneutron reflectors may be used so that the neutron reflectors areappropriately sized without using excess material, as well as, reducingthe weight, transport costs, and/or production costs of the neutronreflectors. The neutron reflectors may reflect neutrons generated by anuclear reaction in nuclear pebble heaters 2198. In certain embodiments,neutron reflectors have a similar size and/or shape to nuclear pebbleheaters 2198. Neutron reflectors and/or neutron moderators may bespherical or other easily moved shaped to facilitate placement and/orremoval in nuclear heater assembly 2192.

Positioning one or more neutron reflectors and/or neutron moderatorsbetween nuclear pebble heaters 2198 in fuel conduit 2196 allows for theadjustment of the energy per unit length produced by the fuel conduitwhen the nuclear pebble heaters are positioned and activated. Activatednuclear pebble heaters 2198 have a decaying energy production curve overtime. Nuclear pebble heaters are able to produce more energy earlier intheir lifetime with their power output decreasing at a predictable ratethroughout their lifetime. In some embodiments, as the power of a set ofnuclear pebble heaters 2198 positioned in fuel conduit 2196 decreasesover time, a number of neutron reflectors positioned between nuclearpebble heaters may be decreased. Decreasing the number of neutronreflectors may increase the density of nuclear pebble heaters (number ofnuclear pebble heaters per unit length) in the fuel conduit and, thus,compensate for the natural decay of the nuclear pebble heaters overtime. In some embodiments, as neutron reflectors are removed from thefuel conduit, additional nuclear pebble heaters may be positioned in thefuel conduit as required to achieve desired energy output.

As depicted in FIG. 172, nuclear pebble heaters 2198 may be positionedbetween nuclear moderators 2202 in a middle portion of the fuel conduitof the heater assembly to regulate heat production at the middle ofnuclear heater assembly. In some embodiments nuclear moderators 2202 maybe formed of graphite. The graphite may facilitate heat transfer andreflect neutrons. As depicted in FIG. 173, nuclear moderators 2202 maybe positioned between every two nuclear pebble heaters 2198 at the endof the fuel conduit of the heater assembly. In some embodiments nuclearmoderators 2202 may be formed of graphite to facilitate heat transferand reflect neutrons. In some embodiments, the density of nuclear pebbleheaters is increased near the ends of the elements positioned in fuelconduit 2196 to compensate for heat loss and achieve the desired energyoutput. One or more neutron reflectors 2200 (for example, spheresincluding tungsten carbide) may be positioned as the end members of theelements positioned in the fuel conduit.

As depicted in FIG. 175, nuclear pebble heaters 2198, nuclear moderators2202 and/or nuclear reflectors 2200 may be sized so to stack in thefluid conduit 2202. Stacking or packing of nuclear pebble heaters 2198,nuclear moderators 2202 and/or nuclear reflectors 2200 may increase thesolid angle thus increasing heat production from the nuclear pebbleheaters.

As depicted in FIG. 176, outer conduit 2194 may be positioned ingraphite-based cement casing 2208. Outer conduit 2194 may include ironlayer 2210 and stainless steel layer 2212. Iron layer 2210 may reflectneutrons. Stainless steel layer 2212 may be positioned between ironlayer 2210 and casing 2208 to inhibit corrosion of iron layer 2210. Fuelconduit 2196 may include an iron layer to reflect neutrons back to thenuclear pebble heaters. Nuclear pebble heaters 2198 may be positionedbetween nuclear moderators 2202. Nuclear reflectors 2200 may bepositioned at the ends of the series of n nuclear pebble heaters 2198and nuclear moderators 2202.

In some embodiments, partially depleted nuclear pebble heaters are usedto heat a subsurface formation. Nuclear pebble heaters 2198 may beacquired after they have been used for a time in a pebble bed modularreactor facility. The used nuclear pebble heaters 2198 may have theiruranium-235 depleted from an initial value of about 9% to about 3%, fromabout 8% to about 4%, or from about 7% to about 5%. Partially depletednuclear pebble heaters may produce less energy per nuclear pebbleheater, which may allow the use of few or no nuclear reflectors in fuelconduit 2196. Typically, depleted or partially depleted nuclear pebbleheaters are disposed of by underground storage in a proper facility (forexample, encasing the reactors in concrete under the ground). Operatorsof pebble bed modular reactor facilities usually have to incursignificant expenses to properly dispose of the used nuclear pebbleheaters. Therefore, partially depleted nuclear pebble heaters may beacquired for little or no cost from pebble bed modular reactorfacilities. Acquiring partially depleted nuclear pebble heaters forlittle or no cost may reduce the costs of developing and treating thehydrocarbon subsurface formation and may utilize material that wouldotherwise be considered to be useless. In some embodiments, overallcosts for developing and treating the subsurface formation may bedecreased by as much as 95% using nuclear pebble heaters due to the costof the energy required to heat the subsurface formation beingdrastically reduced, even if the nuclear pebble heaters are purchasednew. Moreover, less carbon dioxide will be emitted during the in situheat treatment process when using nuclear heaters as opposed to usingelectrical heaters, burners, or in situ combustion to heat thesubsurface formation.

In some embodiments, as nuclear pebble heaters 2198 in the fuel conduit2196 are depleted in nuclear heater assembly 2192, additional fuelconduits may be positioned in the outer conduit as needed. In oneembodiment, as nuclear pebble heaters in a first fuel conduit havedepleted to such an extent that the first fuel conduit does not producea desired amount of heat per unit length, the first fuel conduit may bepulled from the formation, and a second fuel conduit containing a secondset of nuclear pebble heaters may be inserted into nuclear heaterassembly 2192. The second fuel conduit and second set of nuclear pebbleheaters may provide sufficient heat output to heat the formation asdesired. In some embodiments, two or more fuel conduits containingnuclear pebble heaters may be positioned in the nuclear heater assemblyto increase the heat output from the nuclear heater assembly. Outerconduit 2194 may have an initial size that accommodates two or more fuelconduits.

In some embodiment, nuclear pebble heaters 2198 are specificallydesigned for nuclear heater assembly 2192. Special order nuclear pebbleheaters may be produced with an appropriate amount of enriched uraniumfor the desired heat output of nuclear heater assembly 2192.

In some embodiments, heat transfer fluid 2206 is used in nuclear heaterassembly 2192. Heat transfer fluid 2206 may be supplied to outer conduit2194 and function to ensure even heating of the subsurface formationfrom nuclear pebble materials 2198 in fuel conduit 2196. In someembodiments, one or more nuclear pebble heaters 2198 in fuel conduit2196 may produce more energy than other nuclear pebble heaters in thefuel conduit leading to potential hot spots in the fuel conduit. Hotspots are areas where one or more nuclear pebble heaters are producingmore heat than adjacent nuclear pebble heaters. Heat transfer fluid 2206circulated through outer conduit 2194 over fuel conduit 2196 may helpreduce the effect of hot spots along the fuel conduit. In certainembodiments, heat transfer fluid 2206 includes non-reactive fluids ornon-radioactive isotope forming fluids. For example, heat transfer fluid2206 may include helium gas. Helium gas may inhibit corrosion (forexample, oxidation of carbon) of the nuclear pebble heaters at elevatedtemperatures. Convection and/or conduction of heat by helium gas maysmooth temperature profile inside the nuclear heater assembly. In someembodiments, nuclear pebble heater positioning systems are used toperiodically reposition activated nuclear pebble heaters 2198 in fuelconduit 2196, and to move the nuclear pebble heaters to prevent thedevelopment of hot spots.

In some embodiments, heat transfer fluid 2206 is sealed within outerconduit 2194 without the assistance of additional systems to helpcirculate the fluid. In certain embodiments, heat fluid circulationsystems are employed to ensure heat transfer fluid 2206 is circulatedevenly throughout outer conduit 2194. The circulation system may bepositioned in nuclear heater assembly 2192 (for example, in the outerconduit). In some embodiments, the circulation system is positioned onthe surface and exterior to the nuclear heater assembly.

In some embodiments, the circulation system is used to regulate thetemperature of nuclear heater assembly 2192. For example, thecirculation system may be used to remove heat produced by the nuclearpebble heaters to limit the heat output available to transfer to theformation. The amount of heat removed may be adjusted by controlling theflow rate of heat transfer fluid through the nuclear heater assembly.The heat removed by the heat transfer fluid may be converted toelectricity (for example, using a Kalina and/or Rankine cycle) and/orused to heat other portions of the subsurface formation.

In some embodiments, nuclear pebble heaters 2198 require neutronactivation before they will produce heat. Before activation, the nuclearpebble materials may not be thermally hot. In embodiments whereunactivated nuclear pebble materials are employed in nuclear heaterassembly 2192, the nuclear heater assembly may include an activationsource. The activation source may function as a neutron source capableof initiating the nuclear reaction in the nuclear pebble heaters 2198.The activation source may be shielded until used.

The activation source may be positioned in nuclear heater assembly 2192.The activation source may be used to activate nuclear pebble heaters2198 after they have been positioned in fuel conduit 2196. In someembodiments, the activation source is used to activate nuclear pebbleheaters 2198 as they are positioned in fuel conduit 2196. The activationsource may include a neutron emitting material (for example,californium-252) or a controlled neutron source (for example, a 14 MeVminitron neutron generator). The activation source may be locateddownhole and then withdrawn from the well (for example, on wireline).The activation source may be located in another coiled tubing that islater withdrawn from the well. The activation source, such as theminitron, may be located at the wellhead. The minitron may activate thenuclear pebble heaters as the nuclear pebble heaters are moved into theformation.

Handling systems for the nuclear pebble heaters may be automated orsemi-automated. In some embodiments, upon completion of the treatment ofthe subsurface formation using nuclear heater assembly 2192, theassembly may be permanently sealed and capped leaving the activatednuclear pebble in the formation. For example, nuclear heater assembly2192 may be sealed by filling the outer conduit with concrete.

In some in situ heat treatment embodiments, compressors providecompressed fluid to the treatment area. For example, compressors may beused to provide oxidizing fluid 808 and/or fuel 804 to oxidizers 802depicted in FIG. 146. Also, compressors 876 may be used to supply heattransfer fluid to the formation as depicted in FIG. 166.

A significant cost of the in situ heat treatment process may beoperating the compressor over the life of the in situ heat treatmentprocess if conventional electrical energy sources are used to power thecompressors of the in situ heat treatment process. In some embodiments,nuclear power may be used to generate electricity that operates thecompressors needed for the in situ heat treatment process. The nuclearpower may be supplied by one or more nuclear reactors. The nuclearreactors may be light water reactors, pebble bed reactors, and/or othertypes of nuclear reactors. The nuclear reactors may be located at ornear to the in situ heat treatment process site. Locating the nuclearreactors at or near to the in situ heat treatment process site mayreduce equipment costs and electrical transmission losses over longdistances. The use of nuclear power may reduce or eliminate the amountof carbon dioxide generation associated with operating the compressorsover the life of the in situ heat treatment process.

Excess electricity generated by the nuclear reactors may be used forother in situ heat treatment process needs. For example, excesselectricity may be used to cool fluid for forming a low temperaturebarrier (frozen barrier) around treatment areas, and/or for providingelectricity to treatment facilities located at or near the in situ heattreatment process site. In some embodiments, the electricity or excesselectricity produced by the nuclear reactors may be used to resistivelyheat the conduits used to circulate heat transfer fluid through thetreatment area.

In some embodiments, excess heat available from the nuclear reactors maybe used for other in situ processes. For example, excess heat may beused to heat water or make steam that is used in solution miningprocesses. In some embodiments, excess heat from the nuclear reactorsmay be used to heat fluids used in the treatment facilities located nearor at the in situ heat treatment site.

Circulation systems may be used to heat portions of the formation.Production wells in the formation are used to remove produced fluids.After production from the formation has ended, the circulation systemmay be used to recover heat from the formation. FIG. 166 depicts anembodiment of a circulation system. Heat transfer fluid may becirculated through heaters 760 after heat supply 870 is disconnectedfrom the circulation system. The heat transfer fluid may be a differentheat transfer fluid than the heat transfer fluid used to heat theformation. Heat transfers from the heated formation to the heat transferfluid. The heat transfer fluid may be used to heat another portion ofthe formation or the heat transfer fluid may be used for other purposes.In some embodiments, water is introduced into heaters 760 to producesteam. In some embodiments, low temperature steam is introduced intoheaters 760 so that the passage of the steam through the heatersincreases the temperature of the steam. Other heat transfer fluidsincluding natural or synthetic oils, such as Syltherm oil (Dow CorningCorporation (Midland, Mich., U.S.A.), may be used instead of steam orwater.

In some embodiments, the circulation system may be used in conjunctionwith electrical heating. In some embodiments, at least a portion of thepipe in the U-shaped wellbores adjacent to portions of the formationthat are to be heated is made of a ferromagnetic material. For example,the piping adjacent to a layer or layers of the formation to be heatedis made of 9% to 13% chromium steel, such as 410 stainless steel. Thepipe may be a temperature limited heater when time varying electriccurrent is applied to the piping. The time varying electric current mayresistively heat the piping, which heats the formation. In someembodiments, direct electric current may be used to resistively heat thepiping, which heats the formation.

In some embodiments, the circulation system is used to heat theformation to a first temperature, and electrical energy is used tomaintain the temperature of the formation and/or heat the formation tohigher temperatures. The first temperature may be sufficient to vaporizeaqueous formation fluid in the formation. The first temperature may beat most about 200° C., at most about 300° C., at most about 350° C., orat most about 400° C. Using the circulation system to heat the formationto the first temperature allows the formation to be dry when electricityis used to heat the formation. Heating the dry formation may minimizeelectrical current leakage into the formation.

In some embodiments, the circulation system and electrical heating maybe used to heat the formation to a first temperature. The formation maybe maintained, or the temperature of the formation may be increased fromthe first temperature, using the circulation system and/or electricalheating. In some embodiments, the formation may be raised to the firsttemperature using electrical heating, and the temperature may bemaintained and/or increased using the circulation system. Economicfactors, available electricity, availability of fuel for heating theheat transfer fluid, and other factors may be used to determine whenelectrical heating and/or circulation system heating are to be used.

In certain embodiments, the portion of heater 760 in hydrocarbon layer460 is coupled to lead-in conductors. Lead-in conductors may be locatedin overburden 458. Lead-in conductors may electrically couple theportion of heater 760 in hydrocarbon layer 460 to one or more wellheadsat the surface. Electrical isolators may be located at a junction of theportion of heater 760 in hydrocarbon layer 460 with portions of heater760 in overburden 458 so that the portions of the heater in theoverburden are electrically isolated from the portion of the heater inthe hydrocarbon layer. In some embodiments, the lead-in conductors areplaced inside of the pipe of the closed loop circulation system. In someembodiments, the lead-in conductors are positioned outside of the pipeof the closed loop circulation system. In some embodiments, the lead-inconductors are insulated conductors with mineral insulation, such asmagnesium oxide. The lead-in conductors may include highly electricallyconductive materials such as copper or aluminum to reduce heat losses inoverburden 458 during electrical heating.

In certain embodiments, the portions of heater 760 in overburden 458 maybe used as lead-in conductors. The portions of heater 760 in overburden458 may be electrically coupled to the portion of heater 760 inhydrocarbon layer 460. In some embodiments, one or more electricallyconducting materials (such as copper or aluminum) are coupled (forexample, cladded or welded) to the portions of heater 760 in overburden458 to reduce the electrical resistance of the portions of the heater inthe overburden. Reducing the electrical resistance of the portions ofheater 760 in overburden 458 reduces heat losses in the overburdenduring electrical heating.

In some embodiments, the portion of heater 760 in hydrocarbon layer 460is a temperature limited heater with a self-limiting temperature betweenabout 600° C. and about 1000° C. The portion of heater 760 inhydrocarbon layer 460 may be a 9% to 13% chromium stainless steel. Forexample, portion of heater 760 in hydrocarbon layer 460 may be 410stainless steel. Time-varying current may be applied to the portion ofheater 760 in hydrocarbon layer 460 so that the heater operates as atemperature limited heater.

FIG. 177 depicts a side view representation of an embodiment of a systemfor heating a portion of a formation using a circulated fluid systemand/or electrical heating. Wellheads 450 of heaters 760 may be coupledto heat transfer fluid circulation system 868 by piping. Wellheads 450may also be coupled to electrical power supply system 908. In someembodiments, heat transfer fluid circulation system 868 is disconnectedfrom the heaters when electrical power is used to heat the formation. Insome embodiments, electrical power supply system 908 is disconnectedfrom the heaters when heat transfer fluid circulation system 868 is usedto heat the formation.

Electrical power supply system 908 may include transformer 728 andcables 722, 724. In certain embodiments, cables 722, 724 are capable ofcarrying high currents with low losses. For example, cables 722, 724 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 722 and/or cable 724 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and/or reduce the size of the cables needed to coupletransformer 728 to the heaters. In some embodiments, cables 722, 724 maybe made of carbon nanotubes.

In some embodiments, geothermal energy may be used to heat or preheat atreatment area of an in situ heat treatment process or a treatment areato be solution mined. Geothermal energy may have little or no carbondioxide emissions. In some embodiments, hot fluid may be produced from alayer or layers located below or near the treatment area. The hot fluidmay be steam, water, and/or brine. One or more of the layers may begeothermally pressurized geysers. Hot fluid may be pumped from one ormore of the layers. The layer or layers may be 2 km, 4 km, 8 km or morebelow the surface. The hot fluid may be at a temperature of over 100°C., over 200° C., or over 300° C.

The hot fluid may be produced and circulated through piping in thetreatment area to raise the temperature of the treatment area. In someembodiments, the hot fluid is introduced directly into the treatmentarea. In some embodiments, the hot fluid is circulated through thetreatment area or piping in the treatment area without being produced tothe surface and re-introduced into the treatment area. In someembodiments, the hot fluid may be produced from a location near thetreatment area. The hot fluid may be transported to the treatment area.Once transported to the treatment area, the hot fluid is circulatedthrough piping in the treatment area or the hot fluid is introduceddirectly into the treatment area.

In some embodiments, hot fluid produced from a layer or layers is usedto solution mine minerals from the formation. The hot fluid may be usedto raise the temperature of the formation to a temperature below thedissociation temperature of the minerals but to a temperature highenough to increase the amount of mineral going into solution in a firstfluid introduced into the formation. The hot fluid may be introduceddirectly into the formation as all or a portion of the first fluid, orthe hot fluid may be circulated through piping in the formation.

In some embodiments, hot fluid produced from a layer or layers may beused to heat the treatment area before using electrical energy or othertypes of heat sources to heat the treatment area to pyrolysistemperatures. The hot fluid may not be at a temperature sufficient toraise the temperature of the treatment area to pyrolysis temperatures.Using the hot fluid to heat the treatment area before using electricalheaters or other heat sources to heat the treatment area to pyrolysistemperatures may reduce energy costs for the in situ heat treatmentprocess.

In some embodiments, hot dry rock technology may be used to producesteam or other hot heat transfer fluid from a deep portion of theformation. Injection wells may be drilled to a depth where the formationis hot. The injection wells may be over 2 km, over 4 km, or over 8 kmdeep. Sections of the formation adjacent to the bottom portions of theinjection wells may be hydraulically or otherwise fractured to providelarge contact area with the formation and/or to provide flow paths toheated fluid production wells. Water, steam and/or other heat transferfluid may be introduced into the formation through the injection wells.Heat transfers to the introduced fluid from the formation. Steam and/orhot heat transfer fluid may be produced from the heated fluid productionwells. In some embodiments, the steam and/or hot heat transfer fluid isdirected into the treatment area from the production wells without firstproducing the steam and/or hot heat transfer fluid to the surface. Thesteam and/or hot heat transfer fluid may be used to heat a portion of ahydrocarbon containing formation above the deep hot portion of theformation.

In some embodiments, steam produced from heated fluid production wellsmay be used as the steam for a drive process (for example, a steam floodprocess or steam assisted gravity drainage process). In someembodiments, steam or other hot heat transfer fluid produced throughheated fluid production wells is passed through U-shaped wellbores orother types of wellbores to provide initial heating to the formation. Insome embodiments, cooled steam or water, or cooled heat transfer fluid,resulting from the use of the steam and/or heat transfer fluid from thehot portion of the formation may be collected and sent to the hotportion of the formation to be reheated.

In certain embodiments, a controlled or staged in situ heating andproduction process is used to in situ heat treat a hydrocarboncontaining formation (for example, an oil shale formation). The stagedin situ heating and production process may use less energy input toproduce hydrocarbons from the formation than a continuous or batch insitu heat treatment process. In some embodiments, the staged in situheating and production process is about 30% more efficient in treatingthe formation than the continuous or batch in situ heat treatmentprocess. The staged in situ heating and production process may alsoproduce less carbon dioxide emissions than a continuous or batch in situheat treatment process. In certain embodiments, the staged in situheating and production process is used to treat rich layers in the oilshale formation. Treating only the rich layers may be more economicalthan treating both rich layers and lean layers because heat may bewasted heating the lean layers.

FIG. 178 depicts a top view representation of an embodiment for thestaged in situ heating and producing process for treating the formation.In certain embodiments, heaters 716 are arranged in triangular patterns.In other embodiments, heaters 716 are arranged in any other regular orirregular patterns. The heater patterns may be divided into one or moresections 910, 912, 914, 916, and/or 918. The number of heaters 716 ineach section may vary depending on, for example, properties of theformation or a desired heating rate for the formation. One or moreproduction wells 206 may be located in each section 910, 912, 914, 916,and/or 918. In certain embodiments, production wells 206 are located ator near the centers of the sections. In some embodiments, productionwells 206 are in other portions of sections 910, 912, 914, 916, and 918.Production wells 206 may be located at other locations in sections 910,912, 914, 916, and/or 918 depending on, for example, a desired qualityof products produced from the sections and/or a desired production ratefrom the formation.

In certain embodiments, heaters 716 in one of the sections are turned onwhile the heaters in other sections remain turned off. For example,heaters 716 in section 910 may be turned on while the heaters in theother sections are left turned off. Heat from heaters 716 in section 910may create permeability, mobilize fluids, and/or pyrolysis fluids insection 910. While heat is being provided by heaters 716 in section 910,production well 206 in section 912 may be opened to produce fluids fromthe formation. Some heat from heaters 716 in section 910 may transfer tosection 912 and “pre-heat” section 912. The pre-heating of section 912may create permeability in section 912, mobilize fluids in section 912,and allow fluids to be produced from the section through production well206. As fluids are produced from section 912, the movement of fluidsfrom section 910 to section 912 transfers heat between the sections. Themovement of the hot fluids through the formation increases heat transferwithin the formation. Allowing hot fluids to flow between the sectionsuses the energy of the hot fluids for heating of unheated sectionsrather than removing the heat from the formation by producing the hotfluids directly from section 910. Thus, the movement of the hot fluidsallows for less energy input to get production from the formation thanis required if heat is provided from heaters 716 in both sections to getproduction from the sections.

In some embodiments, section 910 and/or section 912 may be treated priorto turning on heaters 716 to increase the permeability in the sections.For example, the sections may be dewatered to increase the permeabilityin the sections. In some embodiments, steam injection or other fluidinjection may be used to increase the permeability in the sections.

In certain embodiments, after a selected time, heaters 716 in section912 are turned on. Turning on heaters 716 in section 912 may provideadditional heat to sections 910 and 912 to increase the permeability,mobility, and/or pyrolysis of fluids in these sections. In someembodiments, as heaters 716 in section 912 are turned on, production insection 912 is turned off (shut down) and production well 206 in section914 is opened to produce fluids from the formation. Thus, fluid flow inthe formation towards production well 206 in section 914 and section 914is heated by the flow of hot fluids as described above for section 912.In some embodiments, production well 206 in section 912 may be left openafter the heaters are turned on in the section, if desired. This processmay be repeated for subsequent sections in the formation. For example,after a selected time, heaters in section 914 may be turned on andfluids produced from production well 206 in section 916 and so onthrough the formation.

In some embodiments, heat is provided by heaters 716 in alternatingsections (for example, sections 910, 914, and 918) while fluids areproduced from the sections in between the heated sections (for example,sections 912 and 916). After a selected time, heaters 716 in theunheated sections (sections 912 and 916) are turned on and fluids areproduced from one or more of the sections as desired.

In certain embodiments, a smaller heater spacing is used in the stagedin situ heating and producing process than in the continuous or batch insitu heat treatment processes. For example, the continuous or batch insitu heat treatment process may use a heater spacing of about 12 m whilethe in situ staged heating and producing process uses a heater spacingof about 10 m. The staged in situ heating and producing process may usethe smaller heater spacing because the staged process allows forrelatively rapid heating of the formation and expansion of theformation.

In some embodiments, the sequence of heated sections begins with theoutermost sections and moves inwards. For example, for a selected time,heat may be provided by heaters 716 in sections 910 and 918 as fluidsare produced from sections 912 and 916. After the selected time, heaters716 in sections 912 and 916 may be turned on and fluids are producedfrom section 914. After another selected amount of time, heaters 716 insection 914 may be turned on, if needed.

In certain embodiments, sections 910-918 are substantially equal sizedsections. The size and/or location of sections 910-918 may vary based ondesired heating and/or production from the formation. For example,simulation of the staged in situ heating and production processtreatment of the formation may be used to determine the number ofheaters in each section, the optimum pattern of sections and/or thesequence for heater power up and production well startup for the stagedin situ heating and production process. The simulation may account forproperties such as, but not limited to, formation properties and desiredproperties and/or quality in the produced fluids. In some embodiments,heaters 716 at the edges of the treated portions of the formation (forexample, heaters 716 at the left edge of section 910 or the right edgeof section 918) may have tailored or adjusted heat outputs to producedesired heat treatment of the formation.

In some embodiments, the formation is sectioned into a checkerboardpattern for the staged in situ heating and production process. FIG. 179depicts a top view of rectangular checkerboard pattern 920 embodimentfor the staged in situ heating and production process. In someembodiments, heaters in the “A” sections (sections 910A, 912A, 914A,916A, and 918A) may be turned on and fluids are produced from the “B”sections (sections 910B, 912B, 914B, 916B, and 918B). After the selectedtime, heaters in the “B” sections may be turned on. The size and/ornumber of “A” and “B” sections in rectangular checkerboard pattern 920may be varied depending on factors such as, but not limited to, heaterspacing, desired heating rate of the formation, desired production rate,size of treatment area, subsurface geomechanical properties, subsurfacecomposition, and/or other formation properties.

In some embodiments, heaters in sections 910A are turned on and fluidsare produced from sections 910B and/or sections 912B. After the selectedtime, heaters in sections 912A may be turned on and fluids are producedfrom sections 912B and/or 914B. After another selected time, heaters insections 914A may be turned on and fluids are produced from sections914B and/or 916B. After another selected time, heaters in sections 916Amay be turned on and fluids are produced from sections 916B and/or 918B.In some embodiments, heaters in a “B” section that has been producedfrom may be turned on when heaters in the subsequent “A” section areturned on. For example, heaters in section 910B may be turned on whenthe heaters in section 912A are turned on. Other alternating heaterstartup and production sequences may also be contemplated for the insitu staged heating and production process embodiment depicted in FIG.179.

In some embodiments, the formation is divided into a circular, ring, orspiral pattern for the staged in situ heating and production process.FIG. 180 depicts a top view of the ring pattern embodiment for thestaged in situ heating and production process. Sections 910, 912, 914,916, and 918 may be treated with heater startup and production sequencessimilar to the sequences described above for the embodiments depicted inFIG. 178. The heater startup and production sequences for the embodimentdepicted in FIG. 180 may start with section 910 (going inwards towardsthe center) or with section 918 (going outwards from the center).Starting with section 910 may allow expansion of the formation asheating moves towards the center of the ring pattern. Shearing of theformation may be minimized or inhibited because the formation is allowedto expand into heated and/or pyrolyzed portions of the formation. Insome embodiments, the center section (section 918) is cooled aftertreatment.

FIG. 181 depicts a top view of a checkerboard ring pattern embodimentfor the staged in situ heating and production process. The embodimentdepicted in FIG. 181 divides the ring pattern embodiment depicted in 180into a checkerboard pattern similar to the checkerboard pattern depictedin FIG. 179. Sections 910A, 912A, 914A, 916A, 918A, 910B, 912B, 914B,916B, and 918B, depicted in 181, may be treated with heater startup andproduction sequences similar to the sequences described above for theembodiment depicted in 179.

In some embodiments, fluids are injected to drive fluids betweensections of the formation. Injecting fluids such as steam or carbondioxide may increase the mobility of hydrocarbons and may increase theefficiency of the staged in situ heating and production process. In someembodiments, fluids are injected into the formation after the in situheat treatment process to recover heat from the formation. In someembodiments, the fluids injected into the formation for heat recoveryinclude some fluids produced from the formation (for example, carbondioxide, water, and/or hydrocarbons produced from the formation). Insome embodiments, the embodiments depicted in FIGS. 178-181 are used forin situ solution mining of the formation. Hot water or another fluid maybe used to get permeability in the formation at low temperatures forsolution mining.

In certain embodiments, several rectangular checkerboard patterns (forexample, rectangular checkerboard pattern 920 depicted in FIG. 179) areused to treat a treatment area of the formation. FIG. 182 depicts a topview of a plurality of rectangular checkerboard patterns 920(1-36) intreatment area 882 for the staged in situ heating and productionprocess. Treatment area 882 may be enclosed by barrier 922. Each ofrectangular checkerboard patterns 920(1-36) may individually be treatedaccording to embodiments described above for the rectangularcheckerboard patterns.

In certain embodiments, the startup of treatment of rectangularcheckerboard patterns 920(1-36) proceeds in a sequential process. Thesequential process may include starting the treatment of each of therectangular checkerboard patterns one by one sequentially. For example,treatment of a second rectangular checkerboard pattern (for example, theonset of heating of the second rectangular checkerboard pattern) may bestarted after treatment of a first rectangular checkerboard pattern andso on. The startup of treatment of the second rectangular checkerboardpattern may be at any point in time after the treatment of the firstrectangular checkerboard pattern has begun. The time selected forstartup of treatment of the second rectangular checkerboard pattern maybe varied depending on factors such as, but not limited to, desiredheating rate of the formation, desired production rate, subsurfacegeomechanical properties, subsurface composition, and/or other formationproperties. In some embodiments, the startup of treatment of the secondrectangular checkerboard pattern begins after a selected amount offluids have been produced from the first rectangular checkerboardpattern area or after the production rate from the first rectangularcheckerboard pattern increases above a selected value or falls below aselected value.

In some embodiments, the startup sequence for rectangular checkerboardpatterns 920(1-36) is arranged to minimize or inhibit expansion stressesin the formation. In an embodiment, the startup sequence of therectangular checkerboard patterns proceeds in an outward spiralsequence, as shown by the arrows in FIG. 182. The outward spiralsequence proceeds sequentially beginning with treatment of rectangularcheckerboard pattern 920-1, followed by treatment of rectangularcheckerboard pattern 920-2, rectangular checkerboard pattern 920-3,rectangular checkerboard pattern 920-4, and continuing the sequence upto rectangular checkerboard pattern 920-36. Sequentially starting therectangular checkerboard patterns in the outwards spiral sequence mayminimize or inhibit expansion stresses in the formation.

Starting treatment in rectangular checkerboard patterns at or near thecenter of treatment area 882 and moving outwards maximizes the startingdistance from barrier 922. Barrier 922 may be most likely to fail whenheat is provided at or near the barrier. Starting treatment/heating ator near the center of treatment area 882 delays heating of rectangularcheckerboard patterns near barrier 922 until later times of heating intreatment area 882 or at or near the end of production from thetreatment area. Thus, if barrier 922 does fail, the failure of thebarrier occurs after a significant portion of treatment area 882 hasbeen treated.

Starting treatment in rectangular checkerboard patterns at or near thecenter of treatment area 882 and moving outwards also creates open porespace in the inner portions of the outward moving startup pattern. Theopen pore space allows portions of the formation being started at latertimes to expand inwards into the open pore space and, for example,minimize shearing in the formation.

In some embodiments, support sections are left between one or morerectangular checkerboard patterns 920(1-36). The support sections may beunheated sections that provide support against geomechanical shifting,shearing, and/or expansion stress in the formation. In some embodiments,some heat may be provided in the support sections. The heat provided inthe support sections may be less than heat provided inside rectangularcheckerboard patterns 920(1-36). In some embodiments, each of thesupport sections may include alternating heated and unheated sections.In some embodiments, fluids are produced from one or more of theunheated support sections.

In some embodiments, one or more of rectangular checkerboard patterns920(1-36) have varying sizes. For example, the outer rectangularcheckerboard patterns (such as rectangular checkerboard patterns920(21-26) and rectangular checkerboard patterns 920(31-36)) may havesmaller areas and/or numbers of checkerboards. Reducing the area and/orthe number of checkerboards in the outer rectangular checkerboardpatterns may reduce expansion stresses and/or geomechanical shifting inthe outer portions of treatment area 882. Reducing the expansionstresses and/or geomechanical shifting in the outer portions oftreatment area 882 may minimize or inhibit expansion stress and/orshifting stress on barrier 922.

FIG. 183 depicts a side view representation of an embodiment forproducing mobilized fluids from the hydrocarbon formation. In FIG. 183,heaters 716 have substantially horizontal heating sections inhydrocarbon layer 460 (as shown, the heaters have heating sections thatgo into and out of the page). Heaters 716 provide heat to first section2100 of hydrocarbon layer 460. Patterns of heaters, such as triangles,squares, rectangles, hexagons, and/or octagons may be used within firstsection 2100. First section 2100 may be heated at least to temperaturessufficient to mobilize some hydrocarbons within the first section. Insome embodiments, temperature within first section 2100 may be increasedto a pyrolyzation temperature.

In some embodiments, formation fluid is produced from first section2100. The formation fluid may be produced through production wells 206.In some embodiments, the formation fluid is mobilized fluid. Themobilized fluid may include heavy hydrocarbons. An API gravity of thefirst mixture may be less than about 20°, less than about 15°, or lessthan about 10°. In some embodiments, the formation fluid includes atleast some pyrolyzed hydrocarbons. Some hydrocarbons may be pyrolyzed inportions of first section 2100 that are at higher temperatures than aremainder of the first section. For example, portions of formationadjacent heaters 716 may be at somewhat higher temperatures than theremainder of first section 2100. The higher temperature of the formationadjacent to heaters 716 may be sufficient to cause pyrolysis ofhydrocarbons. Some of the pyrolysis product may be produced throughproduction wells 206.

One or more sections (for example, second section 2102 and/or thirdsection 2104) may be above or proximate to first section 2100. Some heatfrom first section 2100 may transfer to second section 2102 and thirdsection 2104. In some embodiments, sufficient heat may transfer fromfirst section 2100 to allow for recovery of some hydrocarbons fromsecond section 2102 and/or third section 2104.

In some embodiments, heat from first section 2100 may mobilize orsubstantially mobilize fluid in second section 2102 and/or third section2104. In some embodiments, a mobilization fluid is provided to secondsection 2102 and/or third section 2104 through injection wells 748A,748B to increase mobilization of hydrocarbons within the second sectionor the third section. Mobilization fluids include, but are not limitedto, water, hydrocarbons, surfactants, polymers, carbon disulfide, ormixtures thereof. The mobilization fluid may increase a flow ofmobilized hydrocarbons into first section 2100. For example, a pressuregradient may be produced between second section 2102 and/or 2104 andfirst section 2100 such that the flow of fluids from the second sectionand/or third section to the first section is increased. The mobilizationfluid may solubilize a portion of the hydrocarbons in second section2102 and/or third section 2104 to form a mixture. Solubilization ofhydrocarbons in second section 2102 and/or third section 2104 may allowthe hydrocarbons to be produced from the second section and/or thirdsection without direct heating of the sections.

Enhanced hydrocarbon recovery methods may be used to produce additionalhydrocarbons from portions of the formation adjacent to treatment areastreated using in situ heat treatment processes. Systems and methods forenhanced hydrocarbons recovery are described in U.S. Pat. Nos. 3,943,160to Farmer et al.; 3,946,812 to Gale et al.; 4,077,471 to Shupe et al.;4,216,079 to Newcombe; 5,318,709 to Wuest et al.; 5,723,423 to VanSlyke; 6,022,834 to Hsu et al.; 6,269,881 to Chou et al.; and 7,055,0602to Shpakoff et al., all of which are incorporated by reference herein.

In some embodiments, second section 2102 and/or third section 2104 maybe treated with a water flood. The water flood may include injectingwater into a portion of second section 2102 and/or third section 2104through injection wells 748A, 748B. Flooding of at least a selectedsection of second section 2102 and/or third section 2104 may water wet aportion of the sections. The water wet portions of the selected sectionmay be pressurized by known methods and a water/hydrocarbon mixture maybe collected using one or more production wells.

In certain embodiments, second section 2102 and/or third section 2104may be treated with a hydrocarbon flood (for example, naphtha, kerosene,diesel, vacuum gas oil, or a mixture thereof). In some embodiments, thehydrocarbons have an aromatic content of at least 1% by weight, at least5% by weight, at least 10% by weight, at least 20% by weight or at least25% by weight. A hydrocarbon flood may include injecting hydrocarbonsinto a portion of second section 2102 and/or third section 2104 throughinjection wells 748A, 748B. In some embodiments, the hydrocarbons areproduced from first section 2100 and/or other portions of the formation.In certain embodiments, the hydrocarbons are produced from theformation, treated to remove heavy fractions of hydrocarbons (forexample, asphaltenes, hydrocarbons having a boiling point of at least300° C., of at least 400° C., at least 500° C., or at least 600° C.) andthe hydrocarbons are re-introduced into the formation. In someembodiments, one section may be treated with a hydrocarbon flood whileanother section is treated with water flood. In some embodiments, waterflooding of a section may be alternated with hydrocarbon flooding of thesection.

In an embodiment, a blend made from hydrocarbon mixtures produced fromfirst section 2100 may be used as a mobilization fluid. The blend mayinclude about 20 weight % light hydrocarbons (or blending agent) orgreater (for example, about 50 weight % or about 80 weight % lighthydrocarbons) and about 80 weight % heavy hydrocarbons or less (forexample, about 50 weight % or about 20 weight % heavy hydrocarbons). Theweight percentage of light hydrocarbons and heavy hydrocarbons may varydepending on, for example, a weight distribution (or API gravity) oflight and heavy hydrocarbons, a relative stability of the blend or adesired API gravity of the blend. For example, in some embodiments, theweight percentage of light hydrocarbons in the blend may be less than 50weight % or less than 20 weight %. In certain embodiments, the weightpercentage of light hydrocarbons may be selected to mix the least amountof light hydrocarbons with heavy hydrocarbons that produces a blend witha desired density or viscosity.

Production from second section 2102 and/or third section 2104 may beenhanced by treating the sections with a polymer and/or monomer thatmobilizes hydrocarbons towards one or more production wells. The polymerand/or monomer may reduce the mobility of a water phase in pores of thehydrocarbon containing formation. The reduction of water mobility mayallow the hydrocarbons to be more easily mobilized through thehydrocarbon containing formation. Polymers that may be used include, butare not limited to, polyacrylamides, partially hydrolyzedpolyacrylamide, polyacrylates, ethylenic copolymers, biopolymers,carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates,polyvinylpyrrolidone, AMPS (2-acrylamide-2-methyl propane sulfonate) orcombinations thereof. Examples of ethylenic copolymers includecopolymers of acrylic acid and acrylamide, acrylic acid and laurylacrylate, lauryl acrylate and acrylamide. Examples of biopolymersinclude xanthan gum and guar gum. In some embodiments, polymers may becrosslinked in situ in the hydrocarbon containing formation. In otherembodiments, polymers may be generated in situ in the hydrocarboncontaining formation. Polymers and polymer preparations for use in oilrecovery are described in U.S. Pat. Nos. 6,427,268 to Zhang et al.;6,439,308 to Wang; 5,654,261 to Smith; 5,284,206 to Surles et al.;5,199,490 to Surles et al.; and 5,103,909 to Morgenthaler et al., all ofwhich are incorporated by reference herein.

In some embodiment, the mobilization fluid may include one or morenonionic additives (for example, alcohols, ethoxylated alcohols,nonionic surfactants and/or sugar based esters). In some embodiments,the mobilization fluid may include one or more anionic surfactants (forexample, sulfates, sulfonates, ethoxylated sulfates, and/or phosphates).

In some embodiments, the mobilization fluid may include carbondisulfide. Hydrogen sulfide, in addition to other sulfur compoundsproduced from the formation, may be converted to carbon disulfide usingknown methods. Suitable methods may include oxidation reaction of thesulfur compound to sulfur and/or sulfur dioxides, and by reaction ofsulfur and/or sulfur dioxides with carbon and/or a carbon containingcompound to form the carbon disulfide formulation. The conversion of thesulfur compounds to carbon disulfide and the use of the carbon disulfidefor oil recovery are described in U.S. Patent Publication No.2006/0254769 to Van Dorp et al., which is incorporated by reference asif fully set forth herein. The carbon disulfide may be introduced intosecond section 2102 and/or third section 2104 as a mobilization fluid.

In certain embodiments, formation fluid is produced from first section2100, second section 2102 and/or third section 2104. The formation fluidmay be produced through production wells 206A, 206B, 206C. The formationfluid produced from second section 2102 and/or third section 2104 mayinclude mobilization fluid, hydrocarbons from the second section 2102and/or third section 2104, hydrocarbons from first section 2100, ormixtures thereof.

Producing fluid from production wells in first section 2100 may lowerthe average pressure in the formation by forming an expansion volume forfluids heated in adjacent sections of the formation. Thus, producingfluid from production wells in the first section 2100 may establish apressure gradient in the formation that draws mobilized fluid fromsecond section 2102 and/or third section 2104 into the first section.

In some embodiments, a pressurizing fluid is provided in second section2102 and/or third section 2104 (for example, through injection wells748A, 748B) to increase mobilization of hydrocarbons within thesections. The pressurizing fluid may enhance the pressure gradient inthe formation to flow mobilized hydrocarbons into first section 2100. Incertain embodiments, the production of fluids from first section 2100allows the pressure in second section 2102 and/or third section 2104 toremain below a selected pressure (for example, a pressure below whichfracturing of the overburden and/or underburden may occur).

Hydrocarbons may be produced from first section 2100, second section2102 and/or third section 2104 such that at least about 30% by weight,at least about 40%, or at least about 50% by weight of the initial massof hydrocarbons in the formation are produced. In other embodiments, atleast about 60% by weight or at least about 70% by weight of the initialmass of hydrocarbons in the formation are produced.

In certain embodiments, hydrocarbons may be produced from the formationsuch that at least about 60% by volume of the initial volume in place ofhydrocarbons is produced from the formation. In some embodiments, atleast about 70% by volume of the initial volume in place of hydrocarbonsor at least about 80% by volume of the initial volume in place ofhydrocarbons may be produced from the formation.

In some embodiments, a pressurizing fluid is provided to second section2102 and/or third section 2104 in combination with the mobilizationfluid to increase mobility of hydrocarbons within the formation. Thepressurizing fluid may include gases such as carbon dioxide, nitrogen,steam, methane, and/or mixtures thereof. In some embodiments, fluidsproduced from the formation (for example, combustion gases, heaterexhaust gases, or produced formation fluids) may be used as pressurizingfluid. Providing a pressurizing fluid may increase a shear rate appliedto hydrocarbon fluids in the formation and decrease the viscosity ofnon-Newtonian hydrocarbon fluids within the formation. In someembodiments, pressurizing fluid is provided to the selected sectionbefore significant heating of the formation. Pressurizing fluidinjection may increase a portion of the formation available forproduction. Pressurizing fluid injection may increase a ratio of energyoutput of the formation (energy content of products produced from theformation) to energy input into the formation (energy costs for treatingthe formation).

Providing the pressurizing fluid may increase a pressure in a selectedsection of the formation. The pressure in the selected section may bemaintained below a selected pressure. For example, the pressure may bemaintained below about 150 bars absolute, about 100 bars absolute, orabout 50 bars absolute. In some embodiments, the pressure may bemaintained below about 35 bars absolute. Pressure may be varieddepending on a number of factors (for example, desired production rateor an initial viscosity of tar in the formation). Injection of a gasinto the formation may result in a viscosity reduction of some of thetar in the formation.

In some embodiments, pressure is maintained by controlling flow of thepressurizing fluid into the selected section. In other embodiments, thepressure is controlled by varying a location or locations for injectingthe pressurizing fluid. In other embodiments, pressure is maintained bycontrolling a pressure and/or production rate at production wells 206.In some embodiments, the pressurized fluid (for example, carbon dioxide)is separated from the produced fluids and re-introduced into theformation. After production has been stopped, the fluid may besequestered in the formation.

The produced fluids may be transported through conduits (pipelines)between the formation and a treatment facility or refinery. The producedfluids may be transported through a pipeline to another location forfurther transportation (for example, the fluids can be transported to afacility at a river or a coast through the pipeline where the fluids canbe further transported by tanker to a processing plant or refinery).

During an in situ heat treatment process, some formation fluid maymigrate outwards from the treatment area. The formation fluid mayinclude benzene and other contaminants. Some portions of the formationthat contaminants migrate to will be subsequently treated when a newtreatment area is defined and processed using the in situ heat treatmentprocess. Such contaminants may be removed or destroyed by the subsequentin situ heat treatment process. Some areas of the formation to whichcontaminants migrate may not become part of a new treatment areasubjected to in situ heat treatment. Migration inhibition systems may beimplemented to inhibit contaminants from migrating to areas in theformation that are not to be subjected to in situ heat treatment.

In some embodiments, a barrier (for example, a low temperature zone orfreeze barrier) surrounds at least a portion of the perimeter of atreatment area. The barrier may be 20 m to 100 m from the closestheaters in the treatment area used in the in situ heat treatment processto heat the formation. Some contaminants may migrate outwards toward thebarrier through fractures or highly permeable zones and condense in theformation.

In some in situ heat treatment embodiments, a migration inhibitionsystem may be used to minimize or eliminate migration of formation fluidfrom the treatment area of the in situ heat treatment process. FIG. 184depicts a representation of a fluid migration inhibition system. Barrier922 may surround treatment area 882. Migration inhibition wells 924 maybe placed in the formation between barrier 922 and treatment area 882.Migration inhibition wells 924 may be offset from wells used to heat theformation and/or from production wells used to produce fluid from theformation. Migration inhibition wells 924 may be placed in formationthat is below pyrolysis and/or dissociation temperatures of minerals inthe formation.

In some embodiments, one or more of the migration inhibition wells 924include heaters. The heaters may be used to heat portions of theformation adjacent to the wells to a relatively low temperature. Therelatively low temperature may be a temperature below a dissociationtemperature of minerals in the formation adjacent to the well or below apyrolysis temperature of hydrocarbons in the formation. The temperaturethat the low temperature heater wells raise the formation to may be lessthan 260° C., less than 230° C., or less than 200° C. In someembodiments, heating elements in low temperature wells 924 may betailored so that the heating elements only heat portions of theformation that have permeability sufficient to allow for the migrationof fluid (for example, fracture systems).

Some or all migration inhibition wells 924 may be injector wells thatallow for the introduction of a sweep fluid into the formation. Theinjector wells may include smart well technology. Sweep fluid may beintroduced into the formation through critical orifices, perforations orother types of openings in the injector wells. In some embodiments, thesweep fluid is carbon dioxide. The carbon dioxide may be carbon dioxideproduced from an in situ heat treatment process. The sweep fluid may beor include other fluids, such as nitrogen, methane or othernon-condensable hydrocarbons, exhaust gases, air, and/or steam. Thesweep fluid may provide positive pressure in the formation outside oftreatment area 882. The positive pressure may inhibit migration offormation fluid from treatment area 882 towards barrier 922. The sweepfluid may move through fractures in the formation toward or intotreatment area 882. The sweep fluid may carry fluids that have migratedaway from treatment area 882 back to the treatment area. The pressure ofthe fluid introduced through migration inhibition wells 924 may bemaintained below the fracture pressure of the formation.

After an in situ process, energy recovery, remediation, and/orsequestration of carbon dioxide or other fluids in the treated area; thetreatment area may still be at an elevated temperature. Sulfur may beintroduced into the formation to act as a drive fluid to removeremaining formation fluid from the formation. The sulfur may beintroduced through outermost wellbores in the formation. The wellboresmay be injection wells, production wells, monitor wells, heater wells,barrier wells, or other types of wells that are converted to use assulfur injection wells. The sulfur may be used to drive fluid inwardstowards production wells in the pattern of wells used during the in situheat treatment process. The wells used as production wells for sulfurmay be production wells, heater wells, injection wells, monitor wells,or other types of wells converted for use as sulfur production wells.

In some embodiments, sulfur may be introduced in the treatment area froman outermost set of wells. Formation fluid may be produced from a firstinward set of wellbores until substantially only sulfur is produced fromthe first inward set of wells. The first inward set of wells may beconverted to injection wells. Sulfur may be introduced in the firstinward set of wells to drive remaining formation fluid towards a secondinward set of wells. The pattern may be continued until sulfur has beenintroduced into all of the treatment area. In some embodiments, a linedrive may be used for introducing the sulfur into the treatment area.

In some embodiments, molten sulfur may be injected into the treatmentarea. The molten sulfur may act as a displacement agent that movesand/or entrains remaining fluid in the treatment area. The molten sulfurmay be injected into the formation from selected wells. The sulfur maybe at a temperature near a melting point of sulfur so that the sulfurhas a relatively low viscosity. In some embodiments, the formation maybe at a temperature above the boiling point of sulfur. Sulfur may beintroduced into the formation as a gas or as a liquid.

Sulfur may be introduced into the formation until substantially onlysulfur is produced from the last sulfur production well or productionwells. When substantially only sulfur is produced from the last sulfurproduction well or production wells, introduction of additional sulfurmay be stopped, and the production from the production well orproduction wells may be stopped. Sulfur in the formation may be allowedto remain in the formation and solidify.

Alternative energy sources may be used to supply electricity forsubsurface electric heaters. Alternative energy sources include, but arenot limited to, wind, off-peak power, hydroelectric power, geothermal,solar, and tidal wave action. Some of these alternative energy sourcesprovide intermittent, time-variable power, or power-variable power. Toprovide power for subsurface electric heaters, power provided by thesealternative energy sources may be conditioned to produce power withappropriate operating parameters (for example, voltage, frequency,and/or current) for the subsurface heaters.

FIG. 185 depicts an embodiment for generating electricity for subsurfaceheaters from an intermittent power source. The generated electricalpower may be used to power other equipment used to treat a subsurfaceformation such as, but not limited to, pumps, computers, or otherelectrical equipment. In certain embodiments, windmill 926 is used togenerate electricity to power heaters 760. Windmill 926 may representone or more windmills in a wind farm. The windmills convert wind to ausable mechanical form of motion. In some embodiments, the wind farm mayinclude advanced windmills as suggested by the National Renewable EnergyLaboratory (Golden, Colo., U.S.A.). In some embodiments, windmill 926varies its power output during a 24 hour period (for example, thewindmill may generate the most power at night). Using windmill 926 asthe power source may reduce the carbon dioxide footprint for supplyingpower to heaters 760. In some embodiments, windmill 926 includes otherintermittent, time-variable, or power-variable power sources.

In some embodiments, gas turbine 928 is used to generate electricity topower heaters 760. Windmill 926 and/or gas turbine 928 may be coupled totransformer 930. Transformer 930 may convert power from windmill 926and/or gas turbine 928 into electrical power with appropriate operatingparameters for heaters 760 (for example, AC or DC power with appropriatevoltage, current, and/or frequency may be generated by the transformer).

In certain embodiments, tap controller 932 is coupled to transformer930, control system 934, and heaters 760. Tap controller 932 may monitorand control transformer 930 to maintain a constant voltage to heaters760, regardless of the load of the heaters. Tap controller 932 maycontrol power output in a range from 5 MVA (megavolt amps) to 500 MVA,from 10 MVA to 400 MVA, or from 20 MVA to 300 MVA. Tap controller 932may be designed to meet selected design requirements such as, but notlimited to, load limitations of components (such as transformer 930,control system 934, and/or heaters 760) and the expected full loadcurrent in the electrical circuit. Tap controller 932 may be anelectromechanical, mechanical, electrical, electromagnetic, or solidstate tap controller. In one embodiments, tap controller 932 is a 32step (±16 steps) electromechanical tap controller obtained from ABB Ltd.(Asea Brown Boveri) (Zurich, Switzerland). Tap controller 932 may be astep controller that changes power in steps over a period of time (forexample, 1 step per minute). Tap controller 932 may operated over apercentage of the total range (for example, ±15% of the voltage or ±10%of the voltage).

As an example, during operation, an overload of voltage may be sent fromtransformer 930. Tap controller 932 may modify the load provided toheaters 760 and distribute the excess load to other heaters and/or otherequipment in need of power. In some embodiments, tap controller 932 maystore the excess load for future use.

Control system 934 may control tap controller 932. Control system 934may be, for example, a computer controller or an analog logic system.Control system 934 may use data supplied from power sensors 936 togenerate predictive algorithms and/or control tap controller 932. Forexample, data may be an amount of power generated from windmill 926, gasturbine 928, and/or transformer 930. Data may also include an amount ofresistive load of heaters 760. Power sensors 936 may be toroidal currentsensors that output voltages that are proportional to the currents inwires passing through the sensors.

Automatic voltage regulation for resistive load of a heater enhances thelife of the heaters and/or allows constant heat output from the heatersto a subsurface formation. Adjusting the load demands instead ofadjusting the power source allows enhanced control of power supplied toheaters and/or other equipment that requires electricity. Power suppliedto heaters 760 may be controlled within selected limits (for example, apower supplied and/or controlled to a heater within 1%, 5%, 10%, or 20%of power required by the heater). Control of power supplied fromalternative energy sources may allow output of prime power at itsrating, allow energy produced (for example, from an intermittent source,a subsurface formation, or a hydroelectric source) to be stored and usedlater, and/or allow use of power generated by intermittent power sourcesto be used as a constant source of energy.

Some hydrocarbon containing formations, such as oil shale formations,may include nahcolite, trona, dawsonite, and/or other minerals withinthe formation. In some embodiments, nahcolite is contained in partiallyunleached or unleached portions of the formation. Unleached portions ofthe formation are parts of the formation where minerals have not beenremoved by groundwater in the formation. For example, in the Piceancebasin in Colorado, U.S.A., unleached oil shale is found below a depth ofabout 500 m below grade. Deep unleached oil shale formations in thePiceance basin center tend to be relatively rich in hydrocarbons. Forexample, about 0.10 liters to about 0.15 liters of oil per kilogram(L/kg) of oil shale may be producible from an unleached oil shaleformation.

Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Nahcolite may be found in formations in the Green River lakebeds inColorado, U.S.A. In some embodiments, at least about 5 weight %, atleast about 10 weight %, or at least about 20 weight % nahcolite may bepresent in the formation. Dawsonite is a mineral that includes sodiumaluminum carbonate (NaAl(CO3)(OH)2). Dawsonite is typically present inthe formation at weight percents greater than about 2 weight % or, insome embodiments, greater than about 5 weight %. Nahcolite and/ordawsonite may dissociate at temperatures used in an in situ heattreatment process. The dissociation is strongly endothermic and mayproduce large amounts of carbon dioxide.

Nahcolite and/or dawsonite may be solution mined prior to, during,and/or following treatment of the formation in situ to avoiddissociation reactions and/or to obtain desired chemical compounds. Incertain embodiments, hot water or steam is used to dissolve nahcolite insitu to form an aqueous sodium bicarbonate solution before the in situheat treatment process is used to process hydrocarbons in the formation.Nahcolite may form sodium ions (Na+) and bicarbonate ions (HCO3-) inaqueous solution. The solution may be produced from the formationthrough production wells, thus avoiding dissociation reactions duringthe in situ heat treatment process. In some embodiments, dawsonite isthermally decomposed to alumina during the in situ heat treatmentprocess for treating hydrocarbons in the formation. The alumina issolution mined after completion of the in situ heat treatment process.

Production wells and/or injection wells used for solution mining and/orfor in situ heat treatment processes may include smart well technology.The smart well technology allows the first fluid to be introduced at adesired zone in the formation. The smart well technology allows thesecond fluid to be removed from a desired zone of the formation.

Formations that include nahcolite and/or dawsonite may be treated usingthe in situ heat treatment process. A perimeter barrier may be formedaround the portion of the formation to be treated. The perimeter barriermay inhibit migration of water into the treatment area. During solutionmining and/or the in situ heat treatment process, the perimeter barriermay inhibit migration of dissolved minerals and formation fluid from thetreatment area. During initial heating, a portion of the formation to betreated may be raised to a temperature below the dissociationtemperature of the nahcolite. The temperature may be at most about 90°C., or in some embodiments, at most about 80° C. The temperature may beany temperature that increases the solvation rate of nahcolite in water,but is also below a temperature at which nahcolite dissociates (aboveabout 95° C. at atmospheric pressure).

A first fluid may be injected into the heated portion. The first fluidmay include water, brine, steam, or other fluids that form a solutionwith nahcolite and/or dawsonite. The first fluid may be at an increasedtemperature, for example, about 90° C., about 95° C., or about 100° C.The increased temperature may be similar to the temperature of theportion of the formation.

In some embodiments, the first fluid is injected at an increasedtemperature into a portion of the formation that has not been heated byheat sources. The increased temperature may be a temperature below aboiling point of the first fluid, for example, about 90° C. for water.Providing the first fluid at an increased temperature increases atemperature of a portion of the formation. In certain embodiments,additional heat may be provided from one or more heat sources in theformation during and/or after injection of the first fluid.

In other embodiments, the first fluid is or includes steam. The steammay be produced by forming steam in a previously heated portion of theformation (for example, by passing water through u-shaped wellbores thathave been used to heat the formation), by heat exchange with fluidsproduced from the formation, and/or by generating steam in standardsteam production facilities. In some embodiments, the first fluid may befluid introduced directly into a hot portion of the portion and producedfrom the hot portion of the formation. The first fluid may then be usedas the first fluid for solution mining.

In some embodiments, heat from a hot previously treated portion of theformation is used to heat water, brine, and/or steam used for solutionmining a new portion of the formation. Heat transfer fluid may beintroduced into the hot previously treated portion of the formation. Theheat transfer fluid may be water, steam, carbon dioxide, and/or otherfluids. Heat may transfer from the hot formation to the heat transferfluid. The heat transfer fluid is produced from the formation throughproduction wells. The heat transfer fluid is sent to a heat exchanger.The heat exchanger may heat water, brine, and/or steam used as the firstfluid to solution mine the new portion of the formation. The heattransfer fluid may be reintroduced into the heated portion of theformation to produce additional hot heat transfer fluid. In someembodiments, heat transfer fluid produced from the formation is treatedto remove hydrocarbons or other materials before being reintroduced intothe formation as part of a remediation process for the heated portion ofthe formation.

Steam injected for solution mining may have a temperature below thepyrolysis temperature of hydrocarbons in the formation. Injected steammay be at a temperature below 250° C., below 300° C., or below 400° C.The injected steam may be at a temperature of at least 150° C., at least135° C., or at least 125° C. Injecting steam at pyrolysis temperaturesmay cause problems as hydrocarbons pyrolyze and hydrocarbon fines mixwith the steam. The mixture of fines and steam may reduce permeabilityand/or cause plugging of production wells and the formation. Thus, theinjected steam temperature is selected to inhibit plugging of theformation and/or wells in the formation.

The temperature of the first fluid may be varied during the solutionmining process. As the solution mining progresses and the nahcolitebeing solution mined is farther away from the injection point, the firstfluid temperature may be increased so that steam and/or water thatreaches the nahcolite to be solution mined is at an elevated temperaturebelow the dissociation temperature of the nahcolite. The steam and/orwater that reaches the nahcolite is also at a temperature below atemperature that promotes plugging of the formation and/or wells in theformation (for example, the pyrolysis temperature of hydrocarbons in theformation).

A second fluid may be produced from the formation following injection ofthe first fluid into the formation. The second fluid may includematerial dissolved in the first fluid. For example, the second fluid mayinclude carbonic acid or other hydrated carbonate compounds formed fromthe dissolution of nahcolite in the first fluid. The second fluid mayalso include minerals and/or metals. The minerals and/or metals mayinclude sodium, aluminum, phosphorus, and other elements.

Solution mining the formation before the in situ heat treatment processallows initial heating of the formation to be provided by heat transferfrom the first fluid used during solution mining. Solution miningnahcolite or other minerals that decompose or dissociate by means ofendothermic reactions before the in situ heat treatment process avoidshaving energy supplied to heat the formation being used to support theseendothermic reactions. Solution mining allows for production of mineralswith commercial value. Removing nahcolite or other minerals before thein situ heat treatment process removes mass from the formation. Thus,less mass is present in the formation that needs to be heated to highertemperatures and heating the formation to higher temperatures may beachieved more quickly and/or more efficiently. Removing mass from theformation also may increase the permeability of the formation.Increasing the permeability may reduce the number of production wellsneeded for the in situ heat treatment process. In certain embodiments,solution mining before the in situ heat treatment process reduces thetime delay between startup of heating of the formation and production ofhydrocarbons by two years or more.

FIG. 186 depicts an embodiment of solution mining well 938. Solutionmining well 938 may include insulated portion 940, input 942, packer944, and return 946. Insulated portion 940 may be adjacent to overburden458 of the formation. In some embodiments, insulated portion 940 is lowconductivity cement. The cement may be low density, low conductivityvermiculite cement or foam cement. Input 942 may direct the first fluidto treatment area 882. Perforations or other types of openings in input942 allow the first fluid to contact formation material in treatmentarea 882. Packer 944 may be a bottom seal for input 942. First fluidpasses through input 942 into the formation. First fluid dissolvesminerals and becomes second fluid. The second fluid may be denser thanthe first fluid. An entrance into return 946 is typically located belowthe perforations or openings that allow the first fluid to enter theformation. Second fluid flows to return 946. The second fluid is removedfrom the formation through return 946.

FIG. 187 depicts a representation of an embodiment of solution miningwell 938. Solution mining well 938 may include input 942 and return 946in casing 948. Inlet 942 and/or return 946 may be coiled tubing.

FIG. 188 depicts a representation of an embodiment of solution miningwell 938. Insulating portions 940 may surround return 946. Input 942 maybe positioned in return 946. In some embodiments, input 942 mayintroduce the first fluid into the treatment area below the entry pointinto return 946. In some embodiments, crossovers may be used to directfirst fluid flow and second fluid flow so that first fluid is introducedinto the formation from input 942 above the entry point of second fluidinto return 946.

FIG. 189 depicts an elevational view of an embodiment of wells used forsolution mining and/or for an in situ heat treatment process. Solutionmining wells 938 may be placed in the formation in an equilateraltriangle pattern. In some embodiments, the spacing between solutionmining wells 938 may be about 36 m. Other spacings may be used. Heatsources 202 may also be placed in an equilateral triangle pattern.Solution mining wells 938 substitute for certain heat sources of thepattern. In the shown embodiment, the spacing between heat sources 202is about 9 m. The ratio of solution mining well spacing to heat sourcespacing is 4. Other ratios may be used if desired. After solution miningis complete, solution mining wells 938 may be used as production wellsfor the in situ heat treatment process.

In some formations, a portion of the formation with unleached mineralsmay be below a leached portion of the formation. The unleached portionmay be thick and substantially impermeable. A treatment area may beformed in the unleached portion. Unleached portion of the formation tothe sides, above and/or below the treatment area may be used as barriersto fluid flow into and out of the treatment area. A first treatment areamay be solution mined to remove minerals, increase permeability in thetreatment area, and/or increase the richness of the hydrocarbons in thetreatment area. After solution mining the first treatment area, in situheat treatment may be used to treat a second treatment area. In someembodiments, the second treatment area is the same as the firsttreatment area. In some embodiments, the second treatment has a smallervolume than the first treatment area so that heat provided by outermostheat sources to the formation do not raise the temperature of unleachedportions of the formation to the dissociation temperature of theminerals in the unleached portions.

In some embodiments, a leached or partially leached portion of theformation above an unleached portion of the formation may includesignificant amounts of hydrocarbon materials. An in situ heating processmay be used to produce hydrocarbon fluids from the unleached portionsand the leached or partially leached portions of the formation. FIG. 190depicts a representation of a formation with unleached zone 950 belowleached zone 952. Unleached zone 950 may have an initial permeabilitybefore solution mining of less than 0.1 millidarcy. Solution miningwells 938 may be placed in the formation. Solution mining wells 938 mayinclude smart well technology that allows the position of first fluidentrance into the formation and second flow entrance into the solutionmining wells to be changed. Solution mining wells 938 may be used toform first treatment area 882′ in unleached zone 950. Unleached zone 950may initially be substantially impermeable. Unleached portions of theformation may form a top barrier and side barriers around firsttreatment area 882′. After solution mining first treatment area 882′,the portions of solution mining wells 938 adjacent to the firsttreatment area may be converted to production wells and/or heater wells.

Heat sources 202 in first treatment area 882′ may be used to heat thefirst treatment area to pyrolysis temperatures. In some embodiments, oneor more heat sources 202 are placed in the formation before firsttreatment area 882′ is solution mined. The heat sources may be used toprovide initial heating to the formation to raise the temperature of theformation and/or to test the functionality of the heat sources. In someembodiments, one or more heat sources are installed during solutionmining of the first treatment area, or after solution mining iscompleted. After solution mining, heat sources 202 may be used to raisethe temperature of at least a portion of first treatment area 882′ abovethe pyrolysis and/or mobilization temperature of hydrocarbons in theformation to result in the generation of mobile hydrocarbons in thefirst treatment area.

Barrier wells 200 may be introduced into the formation. Ends of barrierwells 200 may extend into and terminate in unleached zone 950. Unleachedzone 950 may be impermeable. In some embodiments, barrier wells 200 arefreeze wells. Barrier wells 200 may be used to form a barrier to fluidflow into or out of unleached zone 952. Barrier wells 200, overburden458, and the unleached material above first treatment area 882′ maydefine second treatment area 882″. In some embodiments, a first fluidmay be introduced into second treatment area 882″ through solutionmining wells 938 to raise the initial temperature of the formation insecond treatment area 882″ and remove any residual soluble minerals fromthe second treatment area. In some embodiments, the top barrier abovefirst treatment area 882′ may be solution mined to remove minerals andcombine first treatment area 882′ and second treatment area 882″ intoone treatment area. After solution mining, heat sources may be activatedto heat the treatment area to pyrolysis temperatures.

FIG. 191 depicts an embodiment for solution mining the formation.Barrier 922 (for example, a frozen barrier and/or a grout barrier) maybe formed around a perimeter of treatment area 882 of the formation. Thefootprint defined by the barrier may have any desired shape such ascircular, square, rectangular, polygonal, or irregular shape. Barrier922 may be any barrier formed to inhibit the flow of fluid into or outof treatment area 882. For example, barrier 922 may include one or morefreeze wells that inhibit water flow through the barrier. Barrier 922may be formed using one or more barrier wells 200. Formation of barrier922 may be monitored using monitor wells 956 and/or by monitoringdevices placed in barrier wells 200.

Water inside treatment area 882 may be pumped out of the treatment areathrough injection wells 748 and/or production wells 206. In certainembodiments, injection wells 748 are used as production wells 206 andvice versa (the wells are used as both injection wells and productionwells). Water may be pumped out until a production rate of water is lowor stops.

Heat may be provided to treatment area 882 from heat sources 202. Heatsources may be operated at temperatures that do not result in thepyrolysis of hydrocarbons in the formation adjacent to the heat sources.In some embodiments, treatment area 882 is heated to a temperature fromabout 90° C. to about 120° C. (for example, a temperature of about 90°C., 95° C., 100° C., 110° C., or 120° C.). In certain embodiments, heatis provided to treatment area 882 from the first fluid injected into theformation. The first fluid may be injected at a temperature from about90° C. to about 120° C. (for example, a temperature of about 90° C., 95°C., 100° C., 110° C., or 120° C.). In some embodiments, heat sources 202are installed in treatment area 882 after the treatment area is solutionmined. In some embodiments, some heat is provided from heaters placed ininjection wells 748 and/or production wells 206. A temperature oftreatment area 882 may be monitored using temperature measurementdevices placed in monitoring wells 956 and/or temperature measurementdevices in injection wells 748, production wells 206, and/or heatsources 202.

The first fluid is injected through one or more injection wells 748. Insome embodiments, the first fluid is hot water. The first fluid may mixand/or combine with non-hydrocarbon material that is soluble in thefirst fluid, such as nahcolite, to produce a second fluid. The secondfluid may be removed from the treatment area through injection wells748, production wells 206, and/or heat sources 202. Injection wells 748,production wells 206, and/or heat sources 202 may be heated duringremoval of the second fluid. Heating one or more wells during removal ofthe second fluid may maintain the temperature of the fluid duringremoval of the fluid from the treatment area above a desired value.After producing a desired amount of the soluble non-hydrocarbon materialfrom treatment area 882, solution remaining within the treatment areamay be removed from the treatment area through injection wells 748,production wells 206, and/or heat sources 202. The desired amount of thesoluble non-hydrocarbon material may be less than half of the solublenon-hydrocarbon material, a majority of the soluble non-hydrocarbonmaterial, substantially all of the soluble non-hydrocarbon material, orall of the soluble non-hydrocarbon material. Removing solublenon-hydrocarbon material may produce a relatively high permeabilitytreatment area 882.

Hydrocarbons within treatment area 882 may be pyrolyzed and/or producedusing the in situ heat treatment process following removal of solublenon-hydrocarbon materials. The relatively high permeability treatmentarea allows for easy movement of hydrocarbon fluids in the formationduring in situ heat treatment processing. The relatively highpermeability treatment area provides an enhanced collection area forpyrolyzed and mobilized fluids in the formation. During the in situ heattreatment process, heat may be provided to treatment area 882 from heatsources 202. A mixture of hydrocarbons may be produced from theformation through production wells 206 and/or heat sources 202. Incertain embodiments, injection wells 748 are used as either productionwells and/or heater wells during the in situ heat treatment process.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided to treatment area 882 at or near heat sources202 when a temperature in the formation is above a temperaturesufficient to support oxidation of hydrocarbons. At such a temperature,the oxidant reacts with the hydrocarbons to provide heat in addition toheat provided by electrical heaters in heat sources 202. The controlledamount of oxidant may facilitate oxidation of hydrocarbons in theformation to provide additional heat for pyrolyzing hydrocarbons in theformation. The oxidant may more easily flow through treatment area 882because of the increased permeability of the treatment area afterremoval of the non-hydrocarbon materials. The oxidant may be provided ina controlled manner to control the heating of the formation. The amountof oxidant provided is controlled so that uncontrolled heating of theformation is avoided. Excess oxidant and combustion products may flow toproduction wells in treatment area 882.

Following the in situ heat treatment process, treatment area 882 may becooled by introducing water to produce steam from the hot portion of theformation. Introduction of water to produce steam may vaporize somehydrocarbons remaining in the formation. Water may be injected throughinjection wells 748. The injected water may cool the formation. Theremaining hydrocarbons and generated steam may be produced throughproduction wells 206 and/or heat sources 202. Treatment area 882 may becooled to a temperature near the boiling point of water. The steamproduced from the formation may be used to heat a first fluid used tosolution mine another portion of the formation.

Treatment area 882 may be further cooled to a temperature at which waterwill condense in the formation. Water and/or solvent may be introducedinto and be removed from the treatment area. Removing the condensedwater and/or solvent from treatment area 882 may remove any additionalsoluble material remaining in the treatment area. The water and/orsolvent may entrain non-soluble fluid present in the formation. Fluidmay be pumped out of treatment area 882 through production well 206and/or heat sources 202. The injection and removal of water and/orsolvent may be repeated until a desired water quality within treatmentarea 882 is achieved. Water quality may be measured at injection wells748, heat sources 202, and/or production wells 206. The water qualitymay substantially match or exceed the water quality of treatment area882 prior to treatment.

In some embodiments, treatment area 882 may include a leached zonelocated above an unleached zone. The leached zone may have been leachednaturally and/or by a separate leaching process. In certain embodiments,the unleached zone may be at a depth of at least about 500 m. Athickness of the unleached zone may be between about 100 m and about 500m. However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 882 and/or thetype of formation. In certain embodiments, the first fluid is injectedinto the unleached zone below the leached zone. Heat may also beprovided into the unleached zone.

In certain embodiments, a section of a formation may be left untreatedby solution mining and/or unleached. The unleached section may beproximate a selected section of the formation that has been leachedand/or solution mined by providing the first fluid as described above.The unleached section may inhibit the flow of water into the selectedsection. In some embodiments, more than one unleached section may beproximate a selected section.

Nahcolite may be present in the formation in layers or beds. Prior tosolution mining, such layers may have little or no permeability. Incertain embodiments, solution mining layered or bedded nahcolite fromthe formation causes vertical shifting in the formation. FIG. 192depicts an embodiment of a formation with nahcolite layers in theformation below overburden 458 and before solution mining nahcolite fromthe formation. Hydrocarbon layers 460A have substantially no nahcoliteand hydrocarbon layers 460B have nahcolite. FIG. 193 depicts theformation of FIG. 192 after the nahcolite has been solution mined.Layers 460B have collapsed due to the removal of the nahcolite from thelayers. The collapsing of layers 460B causes compaction of the layersand vertical shifting of the formation. The hydrocarbon richness oflayers 460B is increased after compaction of the layers. In addition,the permeability of layers 460B may remain relatively high aftercompaction due to removal of the nahcolite. The permeability may be morethan 5 darcy, more than 1 darcy, or more than 0.5 darcy after verticalshifting. The permeability may provide fluid flow paths to productionwells when the formation is treated using an in situ heat treatmentprocess. The increased permeability may allow for a large spacingbetween production wells. Distances between production wells for the insitu heat treatment system after solution mining may be greater than 10m, greater than 20 m, or greater than 30 meters. Heater wells may beplaced in the formation after removal of nahcolite and the subsequentvertical shifting. Forming heater wellbores and/or installing heaters inthe formation after the vertical shifting protects the heaters frombeing damaged due to the vertical shifting.

In certain embodiments, removing nahcolite from the formationinterconnects two or more wells in the formation. Removing nahcolitefrom zones in the formation may increase the permeability in the zones.Some zones may have more nahcolite than others and become more permeableas the nahcolite is removed. At a certain time, zones with the increasedpermeability may interconnect two or more wells (for example, injectionwells or production wells) in the formation.

FIG. 194 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.Solution mining wells 938 are used to solution mine hydrocarbon layer460, which contains nahcolite. During the initial portion of thesolution mining process, solution mining wells 938 are used to injectwater and/or other fluids, and to produce dissolved nahcolite fluidsfrom the formation. Each solution mining well 938 is used to injectwater and produce fluid from a near wellbore region as the permeabilityof hydrocarbon layer is not sufficient to allow fluid to flow betweenthe injection wells. In certain embodiments, zone 958 has more nahcolitethan other portions of hydrocarbon layer 460. With increased nahcoliteremoval from zone 958, the permeability of the zone may increase. Thepermeability increases from the wellbores outwards as nahcolite isremoved from zone 958. At some point during solution mining of theformation, the permeability of zone 958 increases to allow solutionmining wells 938 to become interconnected such that fluid will flowbetween the wells. At this time, one solution mining well 938′ may beused to inject water while the other solution mining well is used toproduce fluids from the formation in a continuous process. Injecting inone well and producing from a second well may be more economical andmore efficient in removing nahcolite, as compared to injecting andproducing through the same well. In some embodiments, additional wellsmay be drilled into zone 958 and/or hydrocarbon layer 460 in addition tosolution mining wells 938. The additional wells may be used to circulateadditional water and/or to produce fluids from the formation. The wellsmay later be used as heater wells and/or production wells for the insitu heat treatment process treatment of hydrocarbon layer 460.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium bicarbonate. Sodiumbicarbonate may be used in the food and pharmaceutical industries, inleather tanning, in fire retardation, in wastewater treatment, and influe gas treatment (flue gas desulphurization and hydrogen chloridereduction). The second fluid may be kept pressurized and at an elevatedtemperature when removed from the formation. The second fluid may becooled in a crystallizer to precipitate sodium bicarbonate.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium carbonate, which is alsoreferred to as soda ash. Sodium carbonate may be used in the manufactureof glass, in the manufacture of detergents, in water purification,polymer production, tanning, paper manufacturing, effluentneutralization, metal refining, sugar extraction, and/or cementmanufacturing. The second fluid removed from the formation may be heatedin a treatment facility to form sodium carbonate (soda ash) and/orsodium carbonate brine. Heating sodium bicarbonate will form sodiumcarbonate according to the equation:

2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (EQN. 8)

In certain embodiments, the heat for heating the sodium bicarbonate isprovided using heat from the formation. For example, a heat exchangerthat uses steam produced from the water introduced into the hotformation may be used to heat the second fluid to dissociationtemperatures of the sodium bicarbonate. In some embodiments, the secondfluid is circulated through the formation to utilize heat in theformation for further reaction. Steam and/or hot water may also be addedto facilitate circulation. The second fluid may be circulated through aheated portion of the formation that has been subjected to the in situheat treatment process to produce hydrocarbons from the formation. Atleast a portion of the carbon dioxide generated during sodium carbonatedissociation may be adsorbed on carbon that remains in the formationafter the in situ heat treatment process. In some embodiments, thesecond fluid is circulated through conduits previously used to heat theformation.

In some embodiments, higher temperatures are used in the formation (forexample, above about 120° C., above about 130° C., above about 150° C.,or below about 250° C.) during solution mining of nahcolite. The firstfluid is introduced into the formation under pressure sufficient toinhibit sodium bicarbonate from dissociating to produce carbon dioxide.The pressure in the formation may be maintained at sufficiently highpressures to inhibit such nahcolite dissociation but below pressuresthat would result in fracturing the formation. In addition, the pressurein the formation may be maintained high enough to inhibit steamformation if hot water is being introduced in the formation. In someembodiments, a portion of the nahcolite may begin to decompose in situ.In such cases, nahcolite is removed from the formation as soda ash. Ifsoda ash is produced from solution mining of nahcolite, the soda ash maybe transported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

As described above, in certain embodiments, following removal ofnahcolite from the formation, the formation is treated using the in situheat treatment process to produce formation fluids from the formation.If dawsonite is present in the formation, dawsonite within the heatedportion of the formation decomposes during heating of the formation topyrolysis temperature. Dawsonite typically decomposes at temperaturesabove 270° C. according to the reaction:

2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (EQN. 9)

Sodium carbonate may be removed from the formation by solution miningthe formation with water or other fluid into which sodium carbonate issoluble. In certain embodiments, alumina formed by dawsonitedecomposition is solution mined using a chelating agent. The chelatingagent may be injected through injection wells, production wells, and/orheater wells used for solution mining nahcolite and/or the in situ heattreatment process (for example, injection wells 748, production wells206, and/or heat sources 202 depicted in FIG. 191). The chelating agentmay be an aqueous acid. In certain embodiments, the chelating agent isEDTA (ethylenediaminetetraacetic acid). Other examples of possiblechelating agents include, but are not limited to, ethylenediamine,porphyrins, dimercaprol, nitrilotriacetic acid,diethylenetriaminepentaacetic acid, phosphoric acids, acetic acid,acetoxy benzoic acids, nicotinic acid, pyruvic acid, citric acid,tartaric acid, malonic acid, imidizole, ascorbic acid, phenols, hydroxyketones, sebacic acid, and boric acid. The mixture of chelating agentand alumina may be produced through production wells or other wells usedfor solution mining and/or the in situ heat treatment process (forexample, injection wells 748, production wells 206, and/or heat sources202, which are depicted in FIG. 191). The alumina may be separated fromthe chelating agent in a treatment facility. The recovered chelatingagent may be recirculated back to the formation to solution mine morealumina.

In some embodiments, alumina within the formation may be solution minedusing a basic fluid after the in situ heat treatment process. Basicfluids include, but are not limited to, sodium hydroxide, ammonia,magnesium hydroxide, magnesium carbonate, sodium carbonate, potassiumcarbonate, pyridine, and amines. In an embodiment, sodium carbonatebrine, such as 0.5 Normal Na₂CO₃, is used to solution mine alumina.Sodium carbonate brine may be obtained from solution mining nahcolitefrom the formation. Obtaining the basic fluid by solution mining thenahcolite may significantly reduce costs associated with obtaining thebasic fluid. The basic fluid may be injected into the formation througha heater well and/or an injection well. The basic fluid may combine withalumina to form an alumina solution that is removed from the formation.The alumina solution may be removed through a heater well, injectionwell, or production well.

Alumina may be extracted from the alumina solution in a treatmentfacility. In an embodiment, carbon dioxide is bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from dissociation of nahcolite, from the in situheat treatment process, or from decomposition of the dawsonite duringthe in situ heat treatment process.

In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (for example, atleast about 20 weight %, at least about 30 weight %, or at least about40 weight %) in a depocenter of the formation. The depocenter maycontain only about 5 weight % or less dawsonite on average. However, inbottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce fluid costs,heating costs, and/or equipment costs associated with operating thesolution mining process.

In certain formations, dawsonite composition varies between layers inthe formation. For example, some layers of the formation may havedawsonite and some layers may not. In certain embodiments, more heat isprovided to layers with more dawsonite than to layers with lessdawsonite. Tailoring heat input to provide more heat to certaindawsonite layers more uniformly heats the formation as the reaction todecompose dawsonite absorbs some of the heat intended for pyrolyzinghydrocarbons. FIG. 195 depicts an embodiment for heating a formationwith dawsonite in the formation. Hydrocarbon layer 460 may be cored toassess the dawsonite composition of the hydrocarbon layer. The mineralcomposition may be assessed using, for example, FTIR (Fourier transforminfrared spectroscopy) or x-ray diffraction. Assessing the corecomposition may also assess the nahcolite composition of the core. Afterassessing the dawsonite composition, heater 716 may be placed inwellbore 452. Heater 716 includes sections to provide more heat tohydrocarbon layers with more dawsonite in the layers (hydrocarbon layers460D). Hydrocarbon layers with less dawsonite (hydrocarbon layers 460C)are provided with less heat by heater 716. Heat output of heater 716 maybe tailored by, for example, adjusting the resistance of the heateralong the length of the heater. In one embodiment, heater 716 is atemperature limited heater, described herein, that has a highertemperature limit (for example, higher Curie temperature) in sectionsproximate layers 460D as compared to the temperature limit (Curietemperature) of sections proximate layers 460C. The resistance of heater716 may also be adjusted by altering the resistive conducting materialsalong the length of the heater to supply a higher energy input (wattsper meter) adjacent to dawsonite rich layers.

Solution mining dawsonite and nahcolite may be relatively simpleprocesses that produce alumina and soda ash from the formation. In someembodiments, hydrocarbons produced from the formation using the in situheat treatment process may be fuel for a power plant that producesdirect current (DC) electricity at or near the site of the in situ heattreatment process. The produced DC electricity may be used on the siteto produce aluminum metal from the alumina using the Hall process.Aluminum metal may be produced from the alumina by melting the aluminain a treatment facility on the site. Generating the DC electricity atthe site may save on costs associated with using hydrotreaters,pipelines, or other treatment facilities associated with transportingand/or treating hydrocarbons produced from the formation using the insitu heat treatment process.

In some embodiments, acid may be introduced into the formation throughselected wells to increase the porosity adjacent to the wells. Forexample, acid may be injected if the formation comprises limestone ordolomite. The acid used to treat the selected wells may be acid producedduring in situ heat treatment of a section of the formation (forexample, hydrochloric acid), or acid produced from byproducts of the insitu heat treatment process (for example, sulfuric acid produced fromhydrogen sulfide or sulfur).

In some embodiments, a saline rich zone is located at or near anunleached portion of the formation. The saline rich zone may be anaquifer in which water has leached out nahcolite and/or other minerals.A high flow rate may pass through the saline rich zone. Saline waterfrom the saline rich zone may be used to solution mine another portionof the formation. In certain embodiments, a steam and electricitycogeneration facility may be used to heat the saline water prior to usefor solution mining.

FIG. 196 depicts a representation of an embodiment for solution miningwith a steam and electricity cogeneration facility. Treatment area 882may be formed in unleached portion 950 of the formation (for example, anoil shale formation). Several treatment areas 882 may be formed inunleached portion 950 leaving top, side, and/or bottom walls ofunleached formation as barriers around the individual treatment areas toinhibit inflow and outflow of formation fluid during the in situ heattreatment process. The thickness of the walls surrounding the treatmentareas may be 10 m or more. For example, the side wall near closest tosaline zone 2106 may be 60 m or more thick, and the top wall may be 30 mor more thick.

Treatment area 882 may have significant amounts of nahcolite. Salinezone 2106 is located at or near treatment area 882. In certainembodiments, zone 2106 is located up dip from treatment area 882. Zone2106 may be leached or partially leached such that the zone is mainlyfilled with saline water.

In certain embodiments, saline water is removed (pumped) from zone 2106using production well 206. Production well 206 may be located at or nearthe lowest portion of zone 2106 so that saline water flows into theproduction well. Saline water removed from zone 2106 is heated to hotwater and/or steam temperatures in facility 750. Facility 750 may burnhydrocarbons to run generators that produce electricity. Facility 750may burn gaseous and/or liquid hydrocarbons to make electricity. In someembodiments, pulverized coal is used to make electricity. Theelectricity generated may be used to provide electrical power forheaters or other electrical operations (for example, pumping). Wasteheat from the generators is used to make hot water and/or steam from thesaline water. After the in situ heat treatment process of one or moretreatment areas 882 results in the production of hydrocarbons, at leasta portion of the produced hydrocarbons may be used as fuel for facility750.

The hot water and/or steam made by facility 750 is provided to solutionmining well 938. Solution mining well 938 is used to solution minetreatment area 882. Nahcolite and/or other minerals are removed fromtreatment area 882 by solution mining well 938. The nahcolite may beremoved as a nahcolite solution from treatment area 882. The solutionremoved from treatment area 882 may be a brine solution with dissolvednahcolite. Heat from the removed nahcolite solution may be used infacility 750 to heat saline water from zone 2106 and/or other fluids.The nahcolite solution may then be injected through injection well 748into zone 2106. In some embodiments, injection well 748 injects thenahcolite solution into zone 2106 up dip from production well 206.Injection may occur a significant distance up dip so that nahcolitesolution may be continuously injected as saline water is removed fromthe zone without the two fluids substantially intermixing. In someembodiments, the nahcolite solution from treatment area 882 is providedto injection well 748 without passing through facility 750 (thenahcolite solution bypasses the facility).

The nahcolite solution injected into zone 2106 may be left in the zonepermanently or for an extended period of time (for example, aftersolution mining, production well 206 may be shut in). In someembodiments, the nahcolite stored in zone 2106 is accessed at latertimes. The nahcolite may be produced by removing saline water from zone2106 and processing the saline water to make sodium bicarbonate and/orsoda ash.

Solution mining using saline water from zone 2106 and heat from facility750 to heat the saline water may be a high efficiency process forsolution mining treatment area 882. Facility 750 is efficient atproviding heat to the saline water. Using the saline water to solutionmine decreases costs associated with pumping and/or transporting waterto the treatment site. Additionally, solution mining treatment area 882preheats the treatment area for any subsequent heat treatment of thetreatment area, enriches the hydrocarbon content in the treatment areaby removing nahcolite, and/or creates more permeability in the treatmentarea by removing nahcolite.

In certain embodiments, treatment area 882 is further treated using anin situ heat treatment process following solution mining of thetreatment area. A portion of the electricity generated in facility 750may be used to power heaters for the in situ heat treatment process.

In some embodiments, a perimeter barrier may be formed around theportion of the formation to be treated. The perimeter barrier mayinhibit migration of formation fluid into or out of the treatment area.The perimeter barrier may be a frozen barrier and/or a grout barrier.After formation of the perimeter barrier, the treatment area may beprocessed to produce desired products.

Formations that include non-hydrocarbon materials may be treated toremove and/or dissolve a portion of the non-hydrocarbon materials from asection of the formation before hydrocarbons are produced from thesection. In some embodiments, the non-hydrocarbon materials are removedby solution mining. Removing a portion of the non-hydrocarbon materialsmay reduce the carbon dioxide generation sources present in theformation. Removing a portion of the non-hydrocarbon materials mayincrease the porosity and/or permeability of the section of theformation. Removing a portion of the non-hydrocarbon materials mayresult in a raised temperature in the section of the formation.

After solution mining, some of the wells in the treatment may beconverted to heater wells, injection wells, and/or production wells. Insome embodiments, additional wells are formed in the treatment area. Thewells may be heater wells, injection wells, and/or production wells.Logging techniques may be employed to assess the physicalcharacteristics, including any vertical shifting resulting from thesolution mining, and/or the composition of material in the formation.Packing, baffles or other techniques may be used to inhibit formationfluid from entering the heater wells. The heater wells may be activatedto heat the formation to a temperature sufficient to support combustion.

One or more production wells may be positioned in permeable sections ofthe treatment area. Production wells may be horizontally and/orvertically oriented. For example, production wells may be positioned inareas of the formation that have a permeability of greater than 5 darcyor 10 darcy. In some embodiments, production wells may be positionednear a perimeter barrier. A production well may allow water andproduction fluids to be removed from the formation. Positioning theproduction well near a perimeter barrier enhances the flow of fluidsfrom the warmer zones of the formation to the cooler zones.

FIG. 197 depicts an embodiment of a process for treating a hydrocarboncontaining formation with a combustion front. Barrier 922 (for example,a frozen barrier or a grout barrier) may be formed around a perimeter oftreatment area 882 of the formation. The footprint defined by thebarrier may have any desired shape such as circular, square,rectangular, polygonal, or irregular shape. Barrier 922 may be formedusing one or more barrier wells 200. The barrier may be any barrierformed to inhibit the flow of fluid into or out of treatment area 882.In some embodiments, barrier 922 may be a double barrier.

Heat may be provided to treatment area 882 through heaters positioned ininjection wells 748. In some embodiments, the heaters in injection wells748 heat formation adjacent to the injections wells to temperaturessufficient to support combustion. Heaters in injection wells 748 mayraise the formation near the injection wells to temperatures from about90° C. to about 120° C. or higher (for example, a temperature of about90° C., 95° C., 100° C., 110° C., or 120° C.).

Injection wells 748 may be used to introduce a combustion fuel, anoxidant, steam and/or a heat transfer fluid into treatment area 882,either before, during, or after heat is provided to the treatment area882 from heaters. In some embodiments, injection wells 748 are incommunication with each other to allow the introduced fluid to flow fromone well to another. Injection wells 748 may be located at positionsthat are relatively far away from perimeter barrier 922. Introducedfluid may cause combustion of hydrocarbons in treatment area 882. Heatfrom the combustion may heat treatment area 882 and mobilize fluidstoward production wells 206.

A temperature of treatment area 882 may be monitored using temperaturemeasurement devices placed in monitoring wells and/or temperaturemeasurement devices in injection wells 748, production wells 206, and/orheater wells.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided in injection wells 748 to advance a heatfront towards production wells 206. In some embodiments, the controlledamount of oxidant is introduced into the formation after solution mininghas established permeable interconnectivity between at least twoinjection wells. The amount of oxidant is controlled to limit theadvancement rate of the heat front and to limit the temperature of theheat front. The advancing heat front may pyrolyze hydrocarbons. The highpermeability in the formation allows the pyrolyzed hydrocarbons tospread in the formation towards production wells without being overtakenby the advancing heat front.

Vaporized formation fluid and/or gas formed during the combustionprocess may be removed through gas wells 960 and/or injection well 748.Venting of gases through the gas wells and/or the injection well mayforce the combustion front in a desired direction.

In some embodiments, the formation may be heated to a temperaturesufficient to cause pyrolysis of the formation fluid by the steam and/orheat transfer fluid. The steam and/or heat transfer fluid may be heatedto temperatures of about 300° C., about 400° C., about 500° C., or about600° C. In certain embodiments, the steam and/or heat transfer fluid maybe co-injected with the fuel and/or oxidant.

FIG. 198 depicts a representation of a cross-sectional view of anembodiment for treating a hydrocarbon containing formation with acombustion front. As the combustion front is initiated and/or fueledthrough injection wells 748, formation fluid near periphery 962 of thecombustion front becomes mobile and flow towards production wells 206located proximate barrier 922. Injection wells may include smart welltechnology. Combustion products and noncondensable formation fluid maybe removed from the formation through gas wells 960. In someembodiments, no gas wells are formed in the formation. In suchembodiments, formation fluid, combustion products and noncondensableformation fluid are produced through production wells 206. Inembodiments that include gas wells 960, condensable formation fluid maybe produced through production well 206. In some embodiments, productionwell 206 is located below injection well 748. Production well 206 may beabout, or above about 1 m, 5 m, to 10 m or more below injection well748. Production well may be a horizontal well. Periphery 962 of thecombustion front may advance from the toe of production well 206 towardsthe heel of the production well. Production well 206 may include aperforated liner that allows hydrocarbons to flow into the productionwell. In some embodiments, a catalyst may be placed in production well206. The catalyst may upgrade and/or stabilize formation fluid in theproduction well.

Gases may be produced during in situ heat treatment processes and duringmany conventional production processes. Some of the produced gases (forexample, carbon dioxide and/or hydrogen sulfide) when introduced intowater may change the pH of the water to less than 7. Such gases aretypically referred to as sour gas or acidic gas. Introducing sour gasfrom produced fluid into subsurface formations may reduce or eliminatethe need for or size of certain surface facilities (for example, a Clausplant or Scot gas treater). Introducing sour gas from produced formationfluid into subsurface formations may make the formation fluid moreacceptable for transportation, use, and/or processing. Removal of sourgas having a low heating value (for example, carbon dioxide) fromformation fluids may increase the caloric value of the gas streamseparated from the formation fluid.

Net release of sour gas to the atmosphere and/or conversion of sour gasto other compounds may be reduced by utilizing the produced sour gasand/or by storing the sour gas within subsurface formations. In someembodiments, the sour gas is stored in deep saline aquifers. Deep salineaquifers may be at depths of about 900 m or more below the surface. Thedeep saline aquifers may be relatively thick and permeable. A thick andrelatively impermeable formation strata may be located over deep salineaquifers. For example, 500 m or more of shale may be located above thedeep saline aquifer. The water in the deep saline aquifer may beunusable for agricultural or other common uses because of the highmineral content in the water. Over time, the minerals in the water mayreact with introduced sour gas to form precipitates in the deep salineaquifer. The deep saline aquifer used to store sour gas may be below thetreatment area, at another location in the same formation, or in anotherformation. If the deep saline aquifer is located at another location inthe same formation or in another formation, the sour gas may betransported to the deep saline aquifer by pipeline.

In some embodiments, injection wells used to inject sour gas may bevertical, slanted, and/or directionally steered wells with a significanthorizontal or near horizontal portion. The horizontal or near horizontalportion of the injection well may be located near or at the bottom ofthe deep saline aquifer. FIG. 199 depicts a representation of anembodiment of a system for injection of sour gases produced from the insitu heat treatment process into the deep saline aquifer. Formationfluids may be produced from hydrocarbon layer 460. In certainembodiments, formation fluids are produced using an in situ heattreatment process through production well 206. The sour gas (forexample, gas including at least carbon dioxide and hydrogen sulfide) maybe separated from the formation fluids in gas/liquid separator 2108using known gas/liquid separation techniques.

The separated sour gas may be transported to formation 2110 via conduit2118 (for example, a pipeline). Formation 2110 may include aquifer 2112(for example, a deep saline aquifer) and barrier portion 2114 (forexample, shale). The sour gas may be injected into deep saline aquifer2112 through injection well 2116. Injection well 2116 may have verticalportion 2122 and horizontal portion 2124. Horizontal portion 2124 may benear or at the bottom of deep saline aquifer 2112. The sour gas may beless dense than formation fluid in the deep saline aquifer. The sour gasmay diffuse upwards in the aquifer towards barrier layer 2114.Horizontal portion 2124 may allow injection of the sour gas in a largeportion of deep saline aquifer 2112. Openings in horizontal portion 2124may be critical flow orifices so that fluid is introduced substantiallyequally along the length of the horizontal portion.

Cement 2120 may be used to seal conduit 2118 in formation. Cement 2120used in injection wellbores to form seals at the surface and/or at aninterface of deep saline aquifer with barrier layer 2114 may be selectedso that the cement does not degrade due to the temperature, pressure andchemical environment due to exposure to sour gas.

The deep saline aquifer or aquifers used to store sour gas may be atsufficient depth such that the carbon dioxide in the sour gas isintroduced in the formation in a supercritical state. Supercriticalcarbon dioxide injection may maximize the density of the fluidintroduced into the formation. The depths of outlets of injection wellsused to introduce acidic gases in the formation may be 900 m or morebelow the surface.

Injection of sour gas into a non-producing formation and/or using sourgas as flooding agents are described in U.S. Pat. Nos. 7,128,150 toThomas et al.; RE39,244 to Eaton; RE39,077 to Eaton; 6,755,251 to Thomaset al.; 6,283,230 to Peters, all of which are incorporated by referenceas if fully set forth herein.

During production of formation fluids from a subsurface formation,acidic gases may react with water in the formation and produce acids.For example, carbonic acid may be produced from the reaction of carbondioxide with water during heating of the formation. Portions of wellsmade of certain materials, such as carbon steel, may start todeteriorate or corrode in the presence of the produced acids. To inhibitcorrosion due to produced acids (for example, carbonic acid), fluidsand/or polymers (for example, corrosion inhibitors, foaming agents,surfactants, basic fluids, hydrocarbons, high density polyethylene, ormixtures thereof) may be introduced in the wellbore to neutralize and/ordissolve the acids.

In some embodiments, hydrogen sulfide and/or carbon dioxide areseparated from the produced gases and introduced into one or morewellbores in a subsurface formation. Water present in the gas introducedinto the formation may interact with hydrogen sulfide to form a sulfidelayer on metal surfaces of the injection well. Formation of the sulfidelayer may inhibit further corrosion of the metal surfaces of theinjection well by carbonic acid and/or other acids. The formation of thesulfide layer may allow for the use of carbon steel or other relativelyinexpensive alloys during the introduction of sour gas into subsurfaceformations.

In certain embodiments, a temperature measurement tool assesses theactive impedance of an energized heater. The temperature measurementtool may utilize the frequency domain analysis algorithm associated withPartial Discharge measurement technology (PD) coupled with timed domainreflectometer measurement technology (TDR). A set of frequency domainanalysis tools may be applied to a TDR signature. This process mayprovide unique information in the analysis of the energized heater suchas, but not limited to, an impedance log of the entire length of theheater per unit length. The temperature measurement tool may providecertain advantages for assessing the temperature of a downhole heater.

In certain embodiments, the temperature measurement tool assesses theimpedance per unit length and gives a profile on the entire length ofthe heated section of the heater. The impedance profile may be used inassociation with laboratory data for the heater (such as temperature andresistance profiles for heaters measured at various loads andfrequencies) to assess the temperature per unit length of the heatedsection. The impedance profile may also be used to assess variouscomputer models for heaters that are used in association with thereservoir simulations.

In certain embodiments, the temperature measurement tool assesses anaccurate impedance profile of a heater in a specific formation after anumber of heater wells have been installed and energized in the specificformation. The accurate impedance profile may assess the actual reactiveand real power consumption for each heater that is used similarly. Thisinformation may be used to properly size surface electrical distributionequipment and/or eliminate any extra capacity designed to accommodateany anticipated heater impedance turndown ratio or any unknown powerfactor or reactive power consumption for the heaters.

In certain embodiments, the temperature measurement tool is used totroubleshoot malfunctioning heaters and assess the impedance profile ofthe length of the heated section. The impedance profile may be able toaccurately predict the location of a faulted section and its relativeimpedance to ground. This information may be used to accurately assessthe appropriate reduction in surface voltage to allow the heater tocontinue to operate in a limited capacity. This method may be morepreferable than abandoning the heater in the formation.

In certain embodiments, frequency domain PD testing offers an improvedset of PD characterization tools. A basic set of frequency domain PDtesting tools are described in “The Case for Frequency Domain PD TestingIn The Context Of Distribution Cable”, Steven Boggs, ElectricalInsulation Magazine, IEEE, Vol. 19, Issue 4, July-August 2003, pages13-19, which is incorporated by reference as if fully set forth herein.Frequency domain PD detection sensitivity under field conditions may beone to two orders of magnitude greater than for time domain testing as aresult of there not being a need to trigger on the first PD pulse abovethe broadband noise, and the filtering effect of the cable between thePD detection site and the terminations. As a result of this greatlyincreased sensitivity and the set of characterization tools, frequencydomain PD testing has been developed into a highly sensitive andreliable tool for characterizing the condition of distribution cableduring normal operation while the cable is energized, the sensitivityand accuracy of which have been confirmed through independent testing.

EXAMPLES

Non-restrictive examples are set forth below.

Temperature Limited Heater Experimental Data

FIGS. 200-215 depict experimental data for temperature limited heaters.FIG. 200 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a 446 stainless steel rod with adiameter of 2.5 cm and a 410 stainless steel rod with a diameter of 2.5cm. Both rods had a length of 1.8 m. Curves 964-970 depict resistanceprofiles as a function of temperature for the 446 stainless steel rod at440 amps AC (curve 964), 450 amps AC (curve 966), 500 amps AC (curve968), and 10 amps DC (curve 970). Curves 972-978 depict resistanceprofiles as a function of temperature for the 410 stainless steel rod at400 amps AC (curve 972), 450 amps AC (curve 974), 500 amps AC (curve976), 10 amps DC (curve 978). For both rods, the resistance graduallyincreased with temperature until the Curie temperature was reached. Atthe Curie temperature, the resistance fell sharply. Above the Curietemperature, the resistance decreased slightly with increasingtemperature. Both rods show a trend of decreasing resistance withincreasing AC current. Accordingly, the turndown ratio decreased withincreasing current. Thus, the rods provide a reduced amount of heat nearand above the Curie temperature of the rods. In contrast, the resistancegradually increased with temperature through the Curie temperature withthe applied DC current.

FIG. 201 shows electrical resistance (L) profiles as a function oftemperature (° C.) at various applied electrical currents for a copperrod contained in a conduit of Sumitomo HCM12A (a high strength 410stainless steel). The Sumitomo conduit had a diameter of 5.1 cm, alength of 1.8 m, and a wall thickness of about 0.1 cm. Curves 980-990show that at all applied currents (980: 300 amps AC; 982: 350 amps AC;984: 400 amps AC; 986: 450 amps AC; 988: 500 amps AC; 990: 550 amps AC),resistance increased gradually with temperature until the Curietemperature was reached. At the Curie temperature, the resistance fellsharply. As the current increased, the resistance decreased, resultingin a smaller turndown ratio.

FIG. 202 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheath welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1000 through1018 show resistance profiles as a function of temperature for ACapplied currents ranging from 40 amps to 500 amps (1000: 40 amps; 1002:80 amps; 1004: 120 amps; 1006: 160 amps; 1008: 250 amps; 1010: 300 amps;1012: 350 amps; 1014: 400 amps; 1016: 450 amps; 1018: 500 amps). FIG.203 depicts the raw data for curve 1014. FIG. 204 depicts the data forselected curves 1010, 1012, 1014, 1016, 1018, and 1020. At lowercurrents (below 250 amps), the resistance increased with increasingtemperature up to the Curie temperature. At the Curie temperature, theresistance fell sharply. At higher currents (above 250 amps), theresistance decreased slightly with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fellsharply. Curve 1020 shows resistance for an applied DC electricalcurrent of 10 amps. Curve 1020 shows a steady increase in resistancewith increasing temperature, with little or no deviation at the Curietemperature.

FIG. 205 depicts power (watts per meter (W/m)) versus temperature (° C.)at various applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheath welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1022-1030depict power versus temperature for AC applied currents of 300 amps to500 amps (1022: 300 amps; 1024: 350 amps; 1026: 400 amps; 1028: 450amps; 1030: 500 amps). Increasing the temperature gradually decreasedthe power until the Curie temperature was reached. At the Curietemperature, the power decreased rapidly.

FIG. 206 depicts electrical resistance (mΩ) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a copper rod with a diameter of1.3 cm inside an outer conductor of 2.5 cm Schedule 80 410 stainlesssteel pipe with a 0.15 cm thick copper Everdur™ (DuPont Engineering,Wilmington, Del., U.S.A.) welded sheath over the 410 stainless steelpipe and a length of 1.8 m. Curves 1032-1042 show resistance profiles asa function of temperature for AC applied currents ranging from 300 ampsto 550 amps (1032: 300 amps; 1034: 350 amps; 1036: 400 amps; 1038: 450amps; 1040: 500 amps; 1042: 550 amps). For these AC applied currents,the resistance gradually increases with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fallssharply. In contrast, curve 1044 shows resistance for an applied DCelectrical current of 10 amps. This resistance shows a steady increasewith increasing temperature, and little or no deviation at the Curietemperature.

FIG. 207 depicts data of electrical resistance (me) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied electrical currents. Curves 1046, 1048, 1050, 1052,and 1054 depict resistance profiles as a function of temperature for the410 stainless steel rod at 40 amps AC (curve 1052), 70 amps AC (curve1054), 140 amps AC (curve 1046), 230 amps AC (curve 1048), and 10 ampsDC (curve 1050). For the applied AC currents of 140 amps and 230 amps,the resistance increased gradually with increasing temperature until theCurie temperature was reached. At the Curie temperature, the resistancefell sharply. In contrast, the resistance showed a gradual increase withtemperature through the Curie temperature for the applied DC current.

FIG. 208 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot (1.8 m) longAlloy 42-6 rod with a 0.375 inch diameter copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents. Curves 1056, 1058, 1060, 1062, 1064, 1066, 1068,and 1070 depict resistance profiles as a function of temperature for thecopper cored alloy 42-6 rod at 300 A AC (curve 1056), 350 A AC (curve1058), 400 A AC (curve 1060), 450 A AC (curve 1062), 500 A AC (curve1064), 550 A AC (curve 1066), 600 A AC (curve 1068), and 10 A DC (curve1070). For the applied AC currents, the resistance decreased graduallywith increasing temperature until the Curie temperature was reached. Asthe temperature approaches the Curie temperature, the resistancedecreased more sharply. In contrast, the resistance showed a gradualincrease with temperature for the applied DC current.

FIG. 209 depicts data of power output (watts per foot (W/ft)) versustemperature (° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot(1.8 m) long Alloy 42-6 rod with a 0.375 inch diameter copper core (therod has an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents. Curves 1072, 1074, 1076, 1078, 1080, 1082,1084, and 1086 depict power as a function of temperature for the coppercored alloy 42-6 rod at 300 A AC (curve 1072), 350 A AC (curve 1074),400 A AC (curve 1076), 450 A AC (curve 1078), 500 A AC (curve 1080), 550A AC (curve 1082), 600 A AC (curve 1084), and 10 A DC (curve 1086). Forthe applied AC currents, the power output decreased gradually withincreasing temperature until the Curie temperature was reached. As thetemperature approaches the Curie temperature, the power output decreasedmore sharply. In contrast, the power output showed a relatively flatprofile with temperature for the applied DC current.

FIG. 210 depicts data for values of skin depth (cm) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied AC electrical currents. The skin depth was calculatedusing EQN. 10:

δ=R₁ −R ₁×(1−(1/R _(AC) /R _(DC)))1/2;  (EQN. 10)

where δ is the skin depth, R₁ is the radius of the cylinder, R_(AC) isthe AC resistance, and R_(DC) is the DC resistance. In FIG. 210, curves1088-1106 show skin depth profiles as a function of temperature forapplied AC electrical currents over a range of 50 amps to 500 amps(1088: 50 amps; 1090: 100 amps; 1092: 150 amps; 1094: 200 amps; 1096:250 amps; 1098: 300 amps; 1100: 350 amps; 1102: 400 amps; 1104: 450amps; 1106: 500 amps). For each applied AC electrical current, the skindepth gradually increased with increasing temperature up to the Curietemperature. At the Curie temperature, the skin depth increased sharply.

FIG. 211 depicts temperature (° C.) versus time (hrs) for a temperaturelimited heater. The temperature limited heater was a 1.83 m long heaterthat included a copper rod with a diameter of 1.3 cm inside a 2.5 cmSchedule XXH 410 stainless steel pipe and a 0.325 cm copper sheath. Theheater was placed in an oven for heating. Alternating current wasapplied to the heater when the heater was in the oven. The current wasincreased over two hours and reached a relatively constant value of 400amps for the remainder of the time. Temperature of the stainless steelpipe was measured at three points at 0.46 m intervals along the lengthof the heater. Curve 1108 depicts the temperature of the pipe at a point0.46 m inside the oven and closest to the lead-in portion of the heater.Curve 1110 depicts the temperature of the pipe at a point 0.46 m fromthe end of the pipe and furthest from the lead-in portion of the heater.Curve 1112 depicts the temperature of the pipe at about a center pointof the heater. The point at the center of the heater was furtherenclosed in a 0.3 m section of 2.5 cm thick Fiberfrax® (Unifrax Corp.,Niagara Falls, N.Y., U.S.A.) insulation. The insulation was used tocreate a low thermal conductivity section on the heater (a section whereheat transfer to the surroundings is slowed or inhibited (a “hotspot”)). The temperature of the heater increased with time as shown bycurves 1112, 1110, and 1108. Curves 1112, 1110, and 1108 show that thetemperature of the heater increased to about the same value for allthree points along the length of the heater. The resulting temperatureswere substantially independent of the added Fiberfrax® insulation. Thus,the operating temperatures of the temperature limited heater weresubstantially the same despite the differences in thermal load (due tothe insulation) at each of the three points along the length of theheater. Thus, the temperature limited heater did not exceed the selectedtemperature limit in the presence of a low thermal conductivity section.

FIG. 212 depicts temperature (° C.) versus log time (hrs) data for a 2.5cm solid 410 stainless steel rod and a 2.5 cm solid 304 stainless steelrod. At a constant applied AC electrical current, the temperature ofeach rod increased with time. Curve 1114 shows data for a thermocoupleplaced on an outer surface of the 304 stainless steel rod and under alayer of insulation. Curve 1116 shows data for a thermocouple placed onan outer surface of the 304 stainless steel rod without a layer ofinsulation. Curve 1118 shows data for a thermocouple placed on an outersurface of the 410 stainless steel rod and under a layer of insulation.Curve 1120 shows data for a thermocouple placed on an outer surface ofthe 410 stainless steel rod without a layer of insulation. A comparisonof the curves shows that the temperature of the 304 stainless steel rod(curves 1114 and 1116) increased more rapidly than the temperature ofthe 410 stainless steel rod (curves 1118 and 1120). The temperature ofthe 304 stainless steel rod (curves 1114 and 1116) also reached a highervalue than the temperature of the 410 stainless steel rod (curves 1118and 1120). The temperature difference between the non-insulated sectionof the 410 stainless steel rod (curve 1120) and the insulated section ofthe 410 stainless steel rod (curve 1118) was less than the temperaturedifference between the non-insulated section of the 304 stainless steelrod (curve 1116) and the insulated section of the 304 stainless steelrod (curve 1114). The temperature of the 304 stainless steel rod wasincreasing at the termination of the experiment (curves 1114 and 1116)while the temperature of the 410 stainless steel rod had leveled out(curves 1118 and 1120). Thus, the 410 stainless steel rod (thetemperature limited heater) provided better temperature control than the304 stainless steel rod (the non-temperature limited heater) in thepresence of varying thermal loads (due to the insulation).

A 6 foot temperature limited heater element was placed in a 6 foot 347Hstainless steel canister. The heater element was connected to thecanister in a series configuration. The heater element and canister wereplaced in an oven. The oven was used to raise the temperature of theheater element and the canister. At varying temperatures, a series ofelectrical currents were passed through the heater element and returnedthrough the canister. The resistance of the heater element and the powerfactor of the heater element were determined from measurements duringpassing of the electrical currents.

FIG. 213 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) at several currents for a temperature limitedheater with a copper core, a carbon steel ferromagnetic conductor, and a347H stainless steel support member. The ferromagnetic conductor was alow-carbon steel with a Curie temperature of 770° C. The ferromagneticconductor was sandwiched between the copper core and the 347H supportmember. The copper core had a diameter of 0.5″. The ferromagneticconductor had an outside diameter of 0.765″. The support member had anoutside diameter of 1.05″. The canister was a 3″ Schedule 160 347Hstainless steel canister.

Data 1122 depicts electrical resistance versus temperature for 300 A at60 Hz AC applied current. Data 1124 depicts resistance versustemperature for 400 A at 60 Hz AC applied current. Data 1126 depictsresistance versus temperature for 500 A at 60 Hz AC applied current.Curve 1128 depicts resistance versus temperature for 10A DC appliedcurrent. The resistance versus temperature data indicates that the ACresistance of the temperature limited heater linearly increased up to atemperature near the Curie temperature of the ferromagnetic conductor.Near the Curie temperature, the AC resistance decreased rapidly untilthe AC resistance equaled the DC resistance above the Curie temperature.The linear dependence of the AC resistance below the Curie temperatureat least partially reflects the linear dependence of the AC resistanceof 347H at these temperatures. Thus, the linear dependence of the ACresistance below the Curie temperature indicates that the majority ofthe current is flowing through the 347H support member at thesetemperatures.

FIG. 214 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) data at several currents for a temperaturelimited heater with a copper core, a iron-cobalt ferromagneticconductor, and a 347H stainless steel support member. The iron-cobaltferromagnetic conductor was an iron-cobalt conductor with 6% cobalt byweight and a Curie temperature of 834° C. The ferromagnetic conductorwas sandwiched between the copper core and the 347H support member. Thecopper core had a diameter of 0.465″. The ferromagnetic conductor had anoutside diameter of 0.765″. The support member had an outside diameterof 1.05″. The canister was a 3″ Schedule 160 347H stainless steelcanister.

Data 1130 depicts resistance versus temperature for 100 A at 60 Hz. ACapplied current. Data 1132 depicts resistance versus temperature for 400A at 60 Hz AC applied current. Curve 1134 depicts resistance versustemperature for 10A DC. The AC resistance of this temperature limitedheater turned down at a higher temperature than the previous temperaturelimited heater. This was due to the added cobalt increasing the Curietemperature of the ferromagnetic conductor. The AC resistance wassubstantially the same as the AC resistance of a tube of 347H steelhaving the dimensions of the support member. This indicates that themajority of the current is flowing through the 347H support member atthese temperatures. The resistance curves in FIG. 214 are generally thesame shape as the resistance curves in FIG. 213.

FIG. 215 depicts experimentally measured power factor (y-axis) versustemperature (° C.) at two AC currents for the temperature limited heaterwith the copper core, the iron-cobalt ferromagnetic conductor, and the347H stainless steel support member. Curve 1136 depicts power factorversus temperature for 100 A at 60 Hz AC applied current. Curve 1138depicts power factor versus temperature for 400 A at 60 Hz AC appliedcurrent. The power factor was close to unity (1) except for the regionaround the Curie temperature. In the region around the Curietemperature, the non-linear magnetic properties and a larger portion ofthe current flowing through the ferromagnetic conductor produceinductive effects and distortion in the heater that lowers the powerfactor. FIG. 215 shows that the minimum value of the power factor forthis heater remained above 0.85 at all temperatures in the experiment.Because only portions of the temperature limited heater used to heat asubsurface formation may be at the Curie temperature at any given pointin time and the power factor for these portions does not go below 0.85during use, the power factor for the entire temperature limited heaterwould remain above 0.85 (for example, above 0.9 or above 0.95) duringuse.

From the data in the experiments for the temperature limited heater withthe copper core, the iron-cobalt ferromagnetic conductor, and the 347Hstainless steel support member, the turndown ratio (y-axis) wascalculated as a function of the maximum power (W/m) delivered by thetemperature limited heater. The results of these calculations aredepicted in FIG. 216. The curve in FIG. 216 shows that the turndownratio (y-axis) remains above 2 for heater powers up to approximately2000 W/m. This curve is used to determine the ability of a heater toeffectively provide heat output in a sustainable manner. A temperaturelimited heater with the curve similar to the curve in FIG. 216 would beable to provide sufficient heat output while maintaining temperaturelimiting properties that inhibit the heater from overheating ormalfunctioning.

A theoretical model has been used to predict the experimental results.The theoretical model is based on an analytical solution for the ACresistance of a composite conductor. The composite conductor has a thinlayer of ferromagnetic material, with a relative magnetic permeabilityμ₂/μ₀>>1, sandwiched between two non-ferromagnetic materials, whoserelative magnetic permeabilities, μ₁/μ₀ and μ₃/μ₀, are close to unityand within which skin effects are negligible. An assumption in the modelis that the ferromagnetic material is treated as linear. In addition,the way in which the relative magnetic permeability, μ₂/μ₀, is extractedfrom magnetic data for use in the model is far from rigorous.

Magnetic data was obtained for carbon steel as a ferromagnetic material.B versus H curves, and hence relative permeabilities, were obtained fromthe magnetic data at various temperatures up to 1100° F. and magneticfields up to 200 Oe (oersteds). A correlation was found that fitted thedata well through the maximum permeability and beyond. FIG. 217 depictsexamples of relative magnetic permeability (y-axis) versus magneticfield (Oe) for both the found correlations and raw data for carbonsteel. Data 1140 is raw data for carbon steel at 400° F. Data 1142 israw data for carbon steel at 1000° F. Curve 1144 is the foundcorrelation for carbon steel at 400° F. Curve 1146 is the foundcorrelation for carbon steel at 1000° F.

For the dimensions and materials of the copper/carbon steel/347H heaterelement in the experiments above, theoretical calculations were carriedout to calculate magnetic field at the outer surface of the carbon steelas a function of skin depth. Results of the theoretical calculationswere presented on the same plot as skin depth versus magnetic field fromthe correlations applied to the magnetic data from FIG. 217. Thetheoretical calculations and correlations were made for fourtemperatures (200° F., 500° F., 800° F., and 1100° F.) and five totalroot-mean-square (RMS) currents (100 A, 200 A, 300 A, 400 A, and 500 A).

FIG. 218 shows the resulting plots of skin depth (in) versus magneticfield (Oe) for all four temperatures and 400 A current. Curve 1148 isthe correlation from magnetic data at 200° F. Curve 1150 is thecorrelation from magnetic data at 500° F. Curve 1152 is the correlationfrom magnetic data at 800° F. Curve 1154 is the correlation frommagnetic data at 1100° F. Curve 1156 is the theoretical calculation atthe outer surface of the carbon steel as a function of skin depth at200° F. Curve 1158 is the theoretical calculation at the outer surfaceof the carbon steel as a function of skin depth at 500° F. Curve 1160 isthe theoretical calculation at the outer surface of the carbon steel asa function of skin depth at 800° F. Curve 1162 is the theoreticalcalculation at the outer surface of the carbon steel as a function ofskin depth at 1100° F.

The skin depths obtained from the intersections of the same temperaturecurves in FIG. 218 were input into equations based on theory and the ACresistance per unit length was calculated. The total AC resistance ofthe entire heater, including that of the canister, was subsequentlycalculated. A comparison between the experimental and numerical(calculated) results is shown in FIG. 219 for currents of 300 A(experimental data 1164 and numerical curve 1166), 400 A (experimentaldata 1168 and numerical curve 1170), and 500 A (experimental data 1172and numerical curve 1174). Though the numerical results exhibit asteeper trend than the experimental results, the theoretical modelcaptures the close bunching of the experimental data, and the overallvalues are quite reasonable given the assumptions involved in thetheoretical model. For example, one assumption involved the use of apermeability derived from a quasistatic B-H curve to treat a dynamicsystem.

One feature of the theoretical model describing the flow of alternatingcurrent in the three-part temperature limited heater is that the ACresistance does not fall off monotonically with increasing skin depth.FIG. 220 shows the AC resistance (mΩ) per foot of the heater element asa function of skin depth (in.) at 1100° F. calculated from thetheoretical model. The AC resistance may be maximized by selecting theskin depth that is at the peak of the non-monotonical portion of theresistance versus skin depth profile (for example, at about 0.23 in. inFIG. 220).

FIG. 221 shows the power generated per unit length (W/ft) in each heatercomponent (curve 1176 (copper core), curve 1178 (carbon steel), curve1180 (347H outer layer), and curve 1182 (total)) versus skin depth(in.). As expected, the power dissipation in the 347H falls off whilethe power dissipation in the copper core increases as the skin depthincreases. The maximum power dissipation in the carbon steel occurs atthe skin depth of about 0.23 inches and is expected to correspond to theminimum in the power factor, as shown in FIG. 215. The current densityin the carbon steel behaves like a damped wave of wavelength λ=2πδ andthe effect of this wavelength on the boundary conditions at thecopper/carbon steel and carbon steel/347H interface may be behind thestructure in FIG. 220. For example, the local minimum in AC resistanceis close to the value at which the thickness of the carbon steel layercorresponds to λ/4. Formulae may be developed that describe the shapesof the AC resistance versus temperature profiles of temperature limitedheaters for use in simulating the performance of the heaters in aparticular embodiment. The data in FIGS. 213 and 214 show that theresistances initially rise linearly, then drop off increasingly steeplytowards the DC lines.

FIGS. 222 A-C compare the results of the theoretical calculations withexperimental data at 300 A (FIG. 222A), 400 A (FIG. 222B) and 500 A(FIG. 222C). FIG. 222A depicts electrical resistance (mΩ) versustemperature (° F.) at 300 A. Data 1184 is the experimental data at 300A. Curve 1186 is the theoretical calculation at 300 A. Curve 1188 is aplot of resistance versus temperature at 10 A DC. FIG. 222B depictselectrical resistance (mΩ) versus temperature (° F.) at 400 A. Data 1190is the experimental data at 400 A. Curve 1192 is the theoreticalcalculation at 400 A. Curve 1194 is a plot of resistance versustemperature at 10 A DC. FIG. 222C depicts electrical resistance (mΩ)versus temperature (° F.) at 500 A. Data 1196 is the experimental dataat 500 A. Curve 1198 is the theoretical calculation at 500 A. Curve 1200is a plot of resistance versus temperature at 10 A DC.

Temperature Limited Heater Simulations

A numerical simulation (FLUENT available from Fluent USA, Lebanon, N.H.,U.S.A.) was used to compare operation of temperature limited heaterswith three turndown ratios. The simulation was done for heaters in anoil shale formation (Green River oil shale). Simulation conditions were:

-   -   61 m length conductor-in-conduit temperature limited heaters        (center conductor (2.54 cm diameter), conduit outer diameter 7.3        cm)    -   downhole heater test field richness profile for an oil shale        formation    -   16.5 cm (6.5 inch) diameter wellbores at 9.14 m spacing between        wellbores on triangular spacing    -   200 hours power ramp-up time to 820 watts/m initial heat        injection rate    -   constant current operation after ramp up    -   Curie temperature of 720.6° C. for heater    -   formation will swell and touch the heater canisters for oil        shale richnesses at least 0.14 L/kg (35 gals/ton)

FIG. 223 displays temperature (° C.) of a center conductor of aconductor-in-conduit heater as a function of formation depth (m) for atemperature limited heater with a turndown ratio of 2:1. Curves1202-1224 depict temperature profiles in the formation at various timesranging from 8 days after the start of heating to 675 days after thestart of heating (1202: 8 days, 1204: 50 days, 1206: 91 days, 1208: 133days, 1210: 216 days, 1212: 300 days, 1214: 383 days, 1216: 466 days,1218: 550 days, 1220: 591 days, 1222: 633 days, 1224: 675 days). At aturndown ratio of 2:1, the Curie temperature of 720.6° C. was exceededafter 466 days in the richest oil shale layers. FIG. 224 shows thecorresponding heater heat flux (W/m) through the formation for aturndown ratio of 2:1 along with the oil shale richness (1/kg) profile(curve 1226). Curves 1228-1260 show the heat flux profiles at varioustimes from 8 days after the start of heating to 633 days after the startof heating (1228: 8 days; 1230: 50 days; 1232: 91 days; 1234: 133 days;1238: 175 days; 1240: 216 days; 1242: 258 days; 1244: 300 days; 1236:341 days; 1246: 383 days; 1248: 425 days; 1250: 466 days; 1252: 508days; 1254: 550 days; 1256: 591 days; 1258: 633 days; 1260: 675 days).At a turndown ratio of 2:1, the center conductor temperature exceededthe Curie temperature in the richest oil shale layers.

FIG. 225 displays heater temperature (° C.) as a function of formationdepth (m) for a turndown ratio of 3:1. Curves 1262-1284 show temperatureprofiles through the formation at various times ranging from 12 daysafter the start of heating to 703 days after the start of heating (1262:12 days; 1264: 33 days; 1266: 62 days; 1268: 102 days; 1270: 146 days;1272: 205 days; 1274: 271 days; 1276: 354 days; 1278: 467 days; 1280:605 days; 1282: 662 days; 1284: 703 days). At a turndown ratio of 3:1,the Curie temperature was approached after 703 days. FIG. 226 shows thecorresponding heater heat flux (W/m) through the formation for aturndown ratio of 3:1 along with the oil shale richness (1/kg) profile(curve 1286). Curves 1288-1308 show the heat flux profiles at varioustimes from 12 days after the start of heating to 605 days after thestart of heating (1288: 12 days, 1290: 32 days, 1292: 62 days, 1294: 102days, 1296: 146 days, 1298: 205 days, 1300: 271 days, 1302: 354 days,1304: 467 days, 1306: 605 days, 1308: 749 days). The center conductortemperature never exceeded the Curie temperature for the turndown ratioof 3:1. The center conductor temperature also showed a relatively flattemperature profile for the 3:1 turndown ratio.

FIG. 227 shows heater temperature (° C.) as a function of formationdepth (m) for a turndown ratio of 4:1. Curves 1310-1330 show temperatureprofiles through the formation at various times ranging from 12 daysafter the start of heating to 467 days after the start of heating (1310:12 days; 1312: 33 days; 1314: 62 days; 1316: 102 days, 1318: 147 days;1320: 205 days; 1322: 272 days; 1324: 354 days; 1326: 467 days; 1328:606 days, 1330: 678 days). At a turndown ratio of 4:1, the Curietemperature was not exceeded even after 678 days. The center conductortemperature never exceeded the Curie temperature for the turndown ratioof 4:1. The center conductor showed a temperature profile for the 4:1turndown ratio that was somewhat flatter than the temperature profilefor the 3:1 turndown ratio. These simulations show that the heatertemperature stays at or below the Curie temperature for a longer time athigher turndown ratios. For this oil shale richness profile, a turndownratio of at least 3:1 may be desirable.

Simulations have been performed to compare the use of temperaturelimited heaters and non-temperature limited heaters in an oil shaleformation. Simulation data was produced for conductor-in-conduit heatersplaced in 16.5 cm (6.5 inch) diameter wellbores with 12.2 m (40 feet)spacing between heaters using a formation simulator (for example, STARS)and a near wellbore simulator (for example, ABAQUS from ABAQUS, Inc.,Providence, R.I., U.S.A.). Standard conductor-in-conduit heatersincluded 304 stainless steel conductors and conduits. Temperaturelimited conductor-in-conduit heaters included a metal with a Curietemperature of 760° C. for conductors and conduits. Results from thesimulations are depicted in FIGS. 228-230.

FIG. 228 depicts heater temperature (° C.) at the conductor of aconductor-in-conduit heater versus depth (m) of the heater in theformation for a simulation after 20,000 hours of operation. Heater powerwas set at 820 watts/meter until 760° C. was reached, and the power wasreduced to inhibit overheating. Curve 1332 depicts the conductortemperature for standard conductor-in-conduit heaters. Curve 1332 showsthat a large variance in conductor temperature and a significant numberof hot spots developed along the length of the conductor. Thetemperature of the conductor had a minimum value of 490° C. Curve 1334depicts conductor temperature for temperature limitedconductor-in-conduit heaters. As shown in FIG. 228, temperaturedistribution along the length of the conductor was more controlled forthe temperature limited heaters. In addition, the operating temperatureof the conductor was 730° C. for the temperature limited heaters. Thus,more heat input would be provided to the formation for a similar heaterpower using temperature limited heaters.

FIG. 229 depicts heater heat flux (W/m) versus time (yrs) for theheaters used in the simulation for heating oil shale. Curve 1336 depictsheat flux for standard conductor-in-conduit heaters. Curve 1338 depictsheat flux for temperature limited conductor-in-conduit heaters. As shownin FIG. 229, heat flux for the temperature limited heaters wasmaintained at a higher value for a longer period of time than heat fluxfor standard heaters. The higher heat flux may provide more uniform andfaster heating of the formation.

FIG. 230 depicts cumulative heat input (kJ/m)(kilojoules per meter)versus time (yrs) for the heaters used in the simulation for heating oilshale. Curve 1340 depicts cumulative heat input for standardconductor-in-conduit heaters. Curve 1342 depicts cumulative heat inputfor temperature limited conductor-in-conduit heaters. As shown in FIG.230, cumulative heat input for the temperature limited heaters increasedfaster than cumulative heat input for standard heaters. The fasteraccumulation of heat in the formation using temperature limited heatersmay decrease the time needed for retorting the formation. Onset ofretorting of the oil shale formation may begin around an averagecumulative heat input of 1.1×108 kJ/meter. This value of cumulative heatinput is reached around 5 years for temperature limited heaters andbetween 9 and 10 years for standard heaters.

High Voltage Insulated Conductors

Simulations (using STARS) were carried out to simulate heating aformation using the heater embodiments shown in FIGS. 51 and 53. Thesimulation used insulated conductor heaters with Alloy 180 cores withvarious diameters inside jackets with a diameter of 0.625″ and magnesiumoxide insulation between the cores and jackets ((for example, core 508,electrical insulator 500, and jacket 506 in FIGS. 51 and 53). Thevarious core diameters used were 0.125″, 0.115″, 0.1084″, and 0.1016″.The various core diameters produced selected amounts of heater power inthe heater (using three insulated conductors in the conduit for theheater). FIG. 231 depicts a plot of heater power (W/ft) versus corediameter (in.). As shown in FIG. 231, core diameters of 0.1016″ providesa heater power of about 220 W/ft; core diameters of 0.1084″ provides aheater power of about 250 W/ft; core diameters of 0.115″ provides aheater power of about 280 W/ft; and core diameters of 0.125″ provides aheater power of about 333 W/ft.

For the simulation, the insulated conductor heaters were placed in aconduit (for example, conduit 536 n FIGS. 51 and 53) with an outsidediameter of 1.75″. The conduit with the insulated conductors was placedin another outside conduit (an outside tubular) that had an outsidediameter of 3.5″ and an inside diameter of 3.094″. The entire heaterassembly was placed in a 6″ wellbore in the formation.

The simulation was used to simulate heating of 2000 feet of formationdepth (target zone) below an overburden of 1225 feet. The voltageprovided to the heaters was a constant voltage of 4160V. The formationproperties used were for a typical tar sands formation in the PeaceRiver field in Alberta, Canada. The heater spacing was 40 feet.

FIG. 232 depicts power, resistance, and current versus temperature (°F.) for a heater with core diameters of 0.105″. Plot 2126 depicts power(W/ft)(left axis) versus temperature. Plot 2128 depicts current (I) inamps (right axis) versus temperature. Plot 2130 depicts resistance (R)in ohms (right axis) versus temperature. As shown in FIG. 232, heaterpower decreased linearly with increasing temperature with resistance andcurrent varying slightly over the temperature range.

FIG. 233 depicts actual heater power (W/ft) versus time (days) duringthe simulation for three different heater designs (three power outputsbased on three core diameters). Plot 2132 depicts power for a heaterwith a designed heater output of 220 W/ft (0.1016″ core diameters). Plot2134 depicts power for a heater with a designed heater output of 250W/ft (0.1084″ core diameters). Plot 2136 depicts power for a heater witha designed heater output of 280 W/ft (0.115″ core diameters). As shownin FIG. 233, the heater power outputs decrease slightly with time butremain relatively constant over the duration of the simulation.

FIG. 234 depicts heater element temperature (core temperature) (° F.)and average formation temperature (° F.) versus time (days) for threedifferent heater designs (three power outputs based on three corediameters). Plot 2142 depicts heater temperature for the heater with thedesigned heater output of 220 W/ft (0.1016″ core diameters). Plot 2140depicts heater temperature for the heater with the designed heateroutput of 250 W/ft (0.1084″ core diameters). Plot 2138 depicts heatertemperature for the heater with the designed heater output of 280 W/ft(0.115″ core diameters). As shown by plots 2138, 2140, and 2142, theheater temperatures increased relatively linearly over time.

Plot 2148 depicts average formation temperature using the heater withthe designed heater output of 220 W/ft (0.1016″ core diameters). Plot2146 depicts average formation temperature using the heater with thedesigned heater output of 250 W/ft (0.1084″ core diameters). Plot 2144depicts average formation temperature using the heater with the designedheater output of 280 W/ft (0.115″ core diameters). Plot 2150 depicts thetarget temperature for the formation of 527° F. As shown by plots 2144,2146, and 2148, the average formation temperatures increased relativelylinearly over time. In addition, time to reach the target formationtemperature decreased with the higher powered heaters. For the 220 W/ftheater, the time to reach the target formation temperature was about1322 days. For the 250 W/ft heater, the time to reach the targetformation temperature was about 1145 days. For the 280 W/ft heater, thetime to reach the target formation temperature was about 1055 days. Thesimulation shows that heater embodiments shown in FIGS. 51 and 53 haverelatively linear heating properties and may be used to heat subsurfaceformations to desired temperatures.

Triad Pattern Heater Simulation

FIG. 235 depicts cumulative gas production and cumulative oil productionversus time (years) found from a STARS simulation (Computer ModellingGroup, LTD., Calgary, Alberta, Canada) using the temperature limitedheaters and heater pattern depicted in FIGS. 70 and 72. Curve 1344depicts cumulative oil production (m³) for an initial water saturationof 15%. Curve 1346 depicts cumulative gas production (m³) for theinitial water saturation of 15%. Curve 1348 depicts cumulative oilproduction (m³) for an initial water saturation of 85%. Curve 1350depicts cumulative gas production (m³) for the initial water saturationof 85%. As shown by the small differences between curves 1344 and 1348for cumulative oil production and curves 1346 and 1350 for cumulativegas production, the initial water saturation does not substantiallyalter heating of the formation. As a result, the overall production ofhydrocarbons from the formation is also not substantially changed by theinitial water saturation. Using the temperature limited heaters inhibitsvariances in heating of the formation that otherwise may be caused bythe differences in the initial water saturation.

Phase Transformation and Curie Temperature Experimental Calculations

FIG. 236 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy TC3 (0.1%by weight carbon, 5% by weight cobalt, 12% by weight chromium, 0.5% byweight manganese, 0.5% by weight silicon). Curve 1352 depicts weightpercentage of the ferrite phase. Curve 1354 depicts weight percentage ofthe austenite phase. The arrow points to the Curie temperature of thealloy. As shown in FIG. 236, the phase transformation was close to theCurie temperature but did not overlap with the Curie temperature forthis alloy.

FIG. 237 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for iron alloy FM-4(0.1% by weight carbon, 5% by weight cobalt, 0.5% by weight manganese,0.5% by weight silicon). Curve 1356 depicts weight percentage of theferrite phase. Curve 1358 depicts weight percentage of the austenitephase. The arrow points to the Curie temperature of the alloy. As shownin FIG. 237, the phase transformation broadened without chromium in thealloy and the phase transformation overlapped with the Curie temperaturefor this alloy.

Calculations for the Curie temperature (T_(c)) and the phasetransformation behavior were done for various mixtures of cobalt,carbon, manganese, silicon, vanadium, and titanium using computationalthermodynamic software (ThermoCalc is obtained from Thermo-CalcSoftware, Inc., (McMurray, Pa., U.S.A) and JMatPro is obtained fromSente Software, Ltd., (Guildford, United Kingdom)) to predict the effectof additional elements on Curie Temperature for selected compositions,the temperature (A₁) at which ferrite transforms to paramagneticaustenite, and the phases present at those temperatures. An equilibriumcalculation temperature of 700° C. was used in all calculations todetermine the Curie temperature of ferrite. As shown in TABLE 3, as theweight percentage of cobalt in the composition increased, T_(c)increased and A₁ decreased; however, T_(c) remained above A₁. Anincrease in the A₁ temperature may be predicted upon sufficient additionof carbide formers vanadium, titanium, niobium, tantalum, and tungsten.For example, about 0.5% by weight of carbide formers may be used in analloy that includes about 0.1% by weight of carbon. Addition of carbideformers allows replacement of the Fe₃C carbide phase with a MC carbidephase. From the calculations, excess amounts of vanadium appeared to nothave an impact on T_(c), while excess amounts of other carbide formersreduced the T_(c).

TABLE 3 Composition (% by weight, Calculation Results balance being Fe)T_(c) A₁ Co C Mn Si V Ti (EC) (EC) Phases Present (~700EC) 0 0.1 0.5 0.50 0 758 716 ferrite + Fe₃C (FM2) 2 0.1 0.5 0.5 0 0 776 726 ferrite +Fe₃C (FM4) 5 0.1 0.5 0.5 0 0 803 740 ferrite + Fe₃C (FM6) 8 0.1 0.5 0.50 0 829 752 ferrite + Fe₃C (FM8) 5 0.1 0.5 0.5 0.2 0 803 740 ferrite +Fe₃C + VC 5 0.1 0.5 0.5 0.4 0 802 773 ferrite + Fe₃C + VC 5 0.1 0.5 0.50.5 0 802 830 ferrite + VC 5 0.1 0.5 0.5 0.6 0 802 855 ferrite + VC 50.1 0.5 0.5 0.8 0 803 880 ferrite + VC 5 0.1 0.5 0.5 1.0 0 805 896ferrite + VC 5 0.1 0.5 0.5 1.5 0 807 928 ferrite + VC 5 0.1 0.5 0.5 2.00 810 959 ferrite + VC 6 0.1 0.5 0.5 0.5 0 811 835 ferrite + VC 7 0.10.5 0.5 0.5 0 819 839 ferrite + VC 8 0.1 0.5 0.5 0.5 0 828 843 ferrite +VC 9 0.1 0.5 0.5 0.5 0 836 847 ferrite + VC 10 0.1 0.5 0.5 0.5 0 845 852ferrite + VC 11 0.1 0.5 0.5 0.5 0 853 856 ferrite + VC 12 0.1 0.5 0.50.5 0 861 859 ferrite + VC 10 0.1 0.5 0.5 1.0 0 847 907 ferrite + VC 110.1 0.5 0.5 1.0 0 855 909 ferrite + VC 12 0.1 0.5 0.5 1.0 0 863 911ferrite + VC 13 0.1 0.5 0.5 1.0 0 871 913 ferrite + VC 14 0.1 0.5 0.51.0 0 879 915 ferrite + VC 15 0.1 0.5 0.5 1.0 0 886 917 ferrite + VC 170.1 0.5 0.5 1.0 0 902 920 ferrite + VC 20 0.1 0.5 0.5 1.0 0 924 926ferrite + VC 5 0.1 0.5 0.5 0 0.2 802 738 ferrite + Fe₃C + TiC 5 0.1 0.50.5 0 0.3 802 738 ferrite + Fe₃C + TiC 5 0.1 0.5 0.5 0 0.4 802 867ferrite + TiC 5 0.1 0.5 0.5 0 0.45 802 896 ferrite + TiC 5 0.1 0.5 0.5 00.5 801 902 ferrite + TiC 5 0.1 0.5 0.5 0 1.0 795 934 ferrite + TiC 80.1 0.5 0.5 0 0.5 827 905 ferrite + TiC 10 0.1 0.5 0.5 0 0.5 844 908ferrite + TiC 11 0.1 0.5 0.5 0 0.5 852 909 ferrite + TiC 12 0.1 0.5 0.50 0.5 860 911 ferrite + TiC 13 0.1 0.5 0.5 0 0.5 868 912 ferrite + TiC14 0.1 0.5 0.5 0 0.5 876 914 ferrite + TiC 15 0.1 0.5 0.5 0 0.5 884 915ferrite + TiC 17 0.1 0.5 0.5 0 0.5 899 918 ferrite + TiC 18 0.1 0.5 0.50 0.5 907 920 ferrite + TiC 19 0.1 0.5 0.5 0 0.5 914 921 ferrite + TiC20 0.1 0.5 0.5 0 0.5 922 923 ferrite + TiC 21 0.1 0.5 0.5 0 0.5 929 924ferrite + TiC 21 0.1 0.5 0.5 0 0.6 928 926 ferrite + TiC 21 0.1 0.5 0.50 0.7 926 928 ferrite + TiC 21 0.1 0.5 0.5 0 0.8 925 930 ferrite + TiC21 0.1 0.5 0.5 0 1.0 922 934 ferrite + TiC 22 0.1 0.5 0.5 0 1.0 930 935ferrite + TiC 23 0.1 0.5 0.5 0 1.0 937 936 ferrite + TiC

Several iron-cobalt alloys were prepared and their compositions aregiven in TABLE 4. These cast alloys were processed into rod and wire,and the measured and calculated T_(c) for the rods are listed. Averagesof cooling and heating T_(c) measurements were used since noirreversible hysteresis effect was observed during heating and cooling.As shown in TABLE 4, the agreement between calculated T_(c) and themeasured T_(c) was acceptable.

The measured T_(c) were performed by a torus technique in which a toruswas wound with the sample material. A thermocouple was attached midwayalong the length.

TABLE 4 Nominal Composition (% by weight, T_(c) (EC) Alloy balance beingFe) (torus T_(c) (EC) Designation Co C Mn Si technique) (calculated) FM10 0 0 0 768 770 FM2 0 0.1 0.5 0.5 — 758 FM3 5 0 0 0 — 818 FM4 5 0.1 0.50.5 — 803 FM5 8 0 0 0 — 842 FM6 8 0.1 0.5 0.5 — 826 FM7 10 0 0 0 863 859FM8 10 0.1 0.5 0.5 — 846

FIG. 238 depicts the Curie temperature (horizontal bars) and phasetransformation temperature range (slashed vertical bars) for severaliron alloys. Column 1360 is for FM-2 iron-cobalt alloy. Column 1362 isfor FM-4 iron-cobalt alloy. Column 1364 is for FM-6 iron-cobalt alloy.Column 1366 is for FM-8 iron-cobalt alloy. Column 1368 is for TC1 410stainless steel alloy with cobalt. Column 1370 is for TC2 410 stainlesssteel alloy with cobalt. Column 1372 is for TC3 410 stainless steelalloy with cobalt. Column 1374 is for TC4 410 stainless steel alloy withcobalt. Column 1376 is for TC5 410 stainless steel alloy with cobalt. Asshown in FIG. 238, the iron-cobalt alloys (FM-2, FM-4, FM-6, FM-8) hadlarge phase transformation temperature ranges that overlap with theCurie temperature. The 410 stainless steel alloys with cobalt (TC1, TC2,TC3, TC4, TC5) had small phase transformation temperature ranges. Thephase transformation temperature ranges for TC1, TC2, and TC3 were abovethe Curie temperature. The phase transformation temperature range forTC4 was below the Curie temperature. Thus, a temperature limited heaterusing TC4 may self-limit at a temperature below the Curie temperature ofthe TC4.

FIGS. 239-242 depict the effects of alloy addition to iron-cobaltalloys. FIGS. 239 and 240 depict the effects of carbon addition to aniron-cobalt alloy. FIGS. 241 and 242 depict the effects of titaniumaddition to an iron-cobalt alloy.

FIG. 239 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt and 0.4% by weight manganese. Curve 1378depicts weight percentage of the ferrite phase. Curve 1380 depictsweight percentage of the austenite phase. The arrow points to the Curietemperature of the alloy. As shown in FIG. 239, the phase transformationwas close to the Curie temperature but did not overlap with the Curietemperature for this alloy.

FIG. 240 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.01% carbon.Curve 1382 depicts weight percentage of the ferrite phase. Curve 1384depicts weight percentage of the austenite phase. The arrow points tothe Curie temperature of the alloy. As shown in FIGS. 239 and 240, thephase transformation broadened with the addition of carbon to the alloywith the onset of the phase transformation shifting to a lowertemperature. Thus, carbon may be added to an iron alloy to lower theonset temperature and broaden the temperature range of the phasetransformation.

FIG. 241 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, and 0.085%carbon. Curve 1386 depicts weight percentage of the ferrite phase. Curve1388 depicts weight percentage of the austenite phase. The arrow pointsto the Curie temperature of the alloy. As shown in FIG. 241, the phasetransformation overlapped with the Curie temperature.

FIG. 242 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for an iron-cobalt alloywith 5.63% by weight cobalt, 0.4% by weight manganese, 0.085% carbon,and 0.4% titanium. Curve 1390 depicts weight percentage of the ferritephase. Curve 1392 depicts weight percentage of the austenite phase. Thearrow points to the Curie temperature of the alloy. As shown in FIGS.241 and 242, the phase transformation narrowed with the addition oftitanium to the alloy with the onset of the phase transformationshifting to a higher temperature. Thus, titanium may be added to an ironalloy to raise the onset temperature and narrow the temperature range ofthe phase transformation.

FIG. 243 depicts experimental calculations of weight percentages offerrite and austenite phases versus temperature for 410 stainless steeltype alloy (12% by weight chromium, 0.1% by weight carbon, 0.5% byweight manganese, 0.5% by weight silicon, with the balance being iron).Curve 1394 depicts weight percentage of the ferrite phase. Curve 1396depicts weight percentage of the austenite phase. The arrow points tothe Curie temperature of the alloy. As shown in FIG. 243, the Curietemperature is reduced with the addition of chromium.

Calculations for the Curie temperature and the phase transformationbehavior were done for various mixtures of cobalt, carbon, manganese,silicon, vanadium, chromium, and titanium using the computationalthermodynamic software (ThermoCalc and JMatPro) to predict the effect ofadditional elements on Curie Temperature (T_(c)) for selectedcompositions and the temperature (A₁) at which ferrite transforms toparamagnetic austenite. An equilibrium calculation temperature of 700°C. was used in all calculations. As shown in TABLE 5, as the weightpercentage of cobalt in the composition increased, T_(c) increased andA₁ decreased. As shown in TABLE 5, addition of vanadium and/or titaniumincreased A₁. The addition of vanadium may allow increased amounts ofchromium to be used in Curie heaters.

TABLE 5 Composition (% by weight, Calculation balance being Fe) ResultsCo Cr C Mn Si V Ti T_(c) (EC) A₁ (EC) 0 12 0.1 0.5 0.5 0 0 723 814 2 120.1 0.5 0.5 0 0 739 800 4 12 0.1 0.5 0.5 0 0 754 788 6 12 0.1 0.5 0.5 00 769 780 8 12 0.1 0.5 0.5 0 0 783 773 10 12 0.1 0.5 0.5 0 0 797 766 012 0.1 0.5 0.5 1 0 726 2 12 0.1 0.5 0.5 1 0 741 4 12 0.1 0.5 0.5 1 0 7566 12 0.1 0.5 0.5 1 0 770 8 12 0.1 0.5 0.5 1 0 784 794 10 12 0.1 0.5 0.51 0 797 0 12 0.1 0.5 0.5 2 0 726 2 12 0.1 0.5 0.5 2 0 742 6 12 0.1 0.50.5 2 0 772 8 12 0.1 0.5 0.5 2 0 785 817 10 12 0.1 0.5 0.5 2 0 797 0 120.1 0.5 0.5 0 0.5 718 863 2 12 0.1 0.5 0.5 0 0.5 733 825 4 12 0.1 0.50.5 0 0.5 747 803 6 12 0.1 0.5 0.5 0 0.5 761 787 8 12 0.1 0.5 0.5 0 0.5775 775 10 12 0.1 0.5 0.5 0 0.5 788 767 0 12 0.1 0.5 0.5 1 0.5 721 2 120.1 0.5 0.5 1 0.5 736 4 12 0.1 0.5 0.5 1 0.5 750 6 12 0.1 0.5 0.5 1 0.5763 8 12 0.1 0.5 0.5 1 0.5 776 10 12 0.1 0.5 0.5 1 0.5 788 0 12 0.1 0.50.5 2 0.5 725 2 12 0.1 0.5 0.5 2 0.5 738 4 12 0.1 0.5 0.5 2 0.5 752 6 120.1 0.5 0.5 2 0.5 764 8 12 0.1 0.5 0.5 2 0.5 777 10 12 0.1 0.5 0.5 2 0.5788 0 12 0.1 0.5 0.5 0 1 712 >1000 2 12 0.1 0.5 0.5 0 1 727 877 4 12 0.10.5 0.5 0 1 741 836 6 12 0.1 0.5 0.5 0 1 755 810 8 12 0.1 0.5 0.5 0 1768 794 10 12 0.1 0.5 0.5 0 1 781 780 0 12 0.1 0.5 0.5 1 1 715 2 12 0.10.5 0.5 1 1 730 4 12 0.1 0.5 0.5 1 1 743 6 12 0.1 0.5 0.5 1 1 757 8 120.1 0.5 0.5 1 1 770 821 10 12 0.1 0.5 0.5 1 1 782 0 12 0.1 0.5 0.5 2 1718 2 12 0.1 0.5 0.5 2 1 732 4 12 0.1 0.5 0.5 2 1 745 6 12 0.1 0.5 0.5 21 758 8 12 0.1 0.5 0.5 2 1 770 873 10 12 0.1 0.5 0.5 2 1 782 0 12 0.10.3 0.5 0 0 727 826 2 12 0.1 0.3 0.5 0 0 742 810 4 12 0.1 0.3 0.5 0 0758 800 6 12 0.1 0.3 0.5 0 0 772 791 8 12 0.1 0.3 0.5 0 0 786 784 10 120.1 0.3 0.5 0 0 800 777 0 12 0.1 0.3 0.5 1 0 730 2 12 0.1 0.3 0.5 1 0745 4 12 0.1 0.3 0.5 1 0 760 6 12 0.1 0.3 0.5 1 0 774 8 12 0.1 0.3 0.5 10 787 10 12 0.1 0.3 0.5 1 0 801 0 12 0.1 0.3 0.5 2 0 730 2 12 0.1 0.30.5 2 0 746 4 12 0.1 0.3 0.5 2 0 762 6 12 0.1 0.3 0.5 2 0 775 8 12 0.10.3 0.5 2 0 788 10 12 0.1 0.3 0.5 2 0 801 0 12 0.1 0.3 0.5 0 0.5 722 212 0.1 0.3 0.5 0 0.5 737 4 12 0.1 0.3 0.5 0 0.5 751 6 12 0.1 0.3 0.5 00.5 765 8 12 0.1 0.3 0.5 0 0.5 779 10 12 0.1 0.3 0.5 0 0.5 792 0 12 0.10.3 0.5 1 0.5 725 2 12 0.1 0.3 0.5 1 0.5 740 4 12 0.1 0.3 0.5 1 0.5 7536 12 0.1 0.3 0.5 1 0.5 767 8 12 0.1 0.3 0.5 1 0.5 780 10 12 0.1 0.3 0.51 0.5 792 0 12 0.1 0.3 0.5 2 0.5 728 2 12 0.1 0.3 0.5 2 0.5 742 4 12 0.10.3 0.5 2 0.5 755 6 12 0.1 0.3 0.5 2 0.5 768 8 12 0.1 0.3 0.5 2 0.5 78010 12 0.1 0.3 0.5 2 0.5 792 0 12 0.1 0.3 0.5 0 1 715 2 12 0.1 0.3 0.5 01 730 4 12 0.1 0.3 0.5 0 1 745 6 12 0.1 0.3 0.5 0 1 759 8 12 0.1 0.3 0.50 1 772 10 12 0.1 0.3 0.5 0 1 785 0 12 0.1 0.3 0.5 1 1 719 2 12 0.1 0.30.5 1 1 733 4 12 0.1 0.3 0.5 1 1 747 6 12 0.1 0.3 0.5 1 1 760 8 12 0.10.3 0.5 1 1 773 834 10 12 0.1 0.3 0.5 1 1 786 0 12 0.1 0.3 0.5 2 1 722 212 0.1 0.3 0.5 2 1 736 4 12 0.1 0.3 0.5 2 1 749 6 12 0.1 0.3 0.5 2 1 7628 12 0.1 0.3 0.5 2 1 774 886 10 12 0.1 0.3 0.5 2 1 786 7.5 12.25 0.1 0.30.5 0 0 781 785 8.0 12.25 0.1 0.3 0.5 0 0 785 783 8.5 12.25 0.1 0.3 0.50 0 788 781 9.0 12.25 0.1 0.3 0.5 0 0 792 779 9.5 12.25 0.1 0.3 0.5 0 0795 778 10.0 12.25 0.1 0.3 0.5 0 0 798 776 6.0 12.25 0.1 0.5 0.5 0 0 767780 6.5 12.25 0.1 0.5 0.5 0 0 771 778 7.0 12.25 0.1 0.5 0.5 0 0 774 7767.5 12.25 0.1 0.5 0.5 0 0 778 774 7.5 12.25 0.1 0.3 0.5 1 0 782 812 8.012.25 0.1 0.3 0.5 1 0 786 809 8.5 12.25 0.1 0.3 0.5 1 0 789 806 9.012.25 0.1 0.3 0.5 1 0 792 804 9.5 12.25 0.1 0.3 0.5 1 0 795 801 10.012.25 0.1 0.3 0.5 1 0 799 799 7.5 12.25 0.1 0.5 0.5 1 0 779 801 8.012.25 0.1 0.5 0.5 1 0 782 799 8.5 12.25 0.1 0.5 0.5 1 0 785 796 9.012.25 0.1 0.5 0.5 1 0 788 793 9.5 12.25 0.1 0.5 0.5 1 0 792 791 10.012.25 0.1 0.5 0.5 1 0 795 788 7.5 12.25 0.1 0.3 0.5 0 0.5 774 788 8.012.25 0.1 0.3 0.5 0 0.5 777 785 8.5 12.25 0.1 0.3 0.5 0 0.5 781 782 9.012.25 0.1 0.3 0.5 0 0.5 784 780 7.5 12.25 0.1 0.5 0.5 0 0.5 770 777 8.012.25 0.1 0.5 0.5 0 0.5 774 774 8.5 12.25 0.1 0.5 0.5 0 0.5 777 771 7.512.25 0.1 0.3 0.5 1 0.5 775 823 8.0 12.25 0.1 0.3 0.5 1 0.5 778 819 8.512.25 0.1 0.3 0.5 1 0.5 782 814 9.0 12.25 0.1 0.3 0.5 1 0.5 785 810 9.512.25 0.1 0.3 0.5 1 0.5 788 807 10.0 12.25 0.1 0.3 0.5 1 0.5 791 80310.5 12.25 0.1 0.3 0.5 1 0.5 794 800 11.0 12.25 0.1 0.3 0.5 1 0.5 797797 7.5 12.25 0.1 0.5 0.5 1 0.5 771 811 8.0 12.25 0.1 0.5 0.5 1 0.5 775807 8.5 12.25 0.1 0.5 0.5 1 0.5 778 803 9.0 12.25 0.1 0.5 0.5 1 0.5 781799 9.5 12.25 0.1 0.5 0.5 1 0.5 784 796 10.0 12.25 0.1 0.5 0.5 1 0.5 787792 10.5 12.25 0.1 0.5 0.5 1 0.5 790 789

Several iron-chromium alloys were prepared and their compositions aregiven in TABLE 6. These cast alloys were processed into rods and wire,and the calculated and measured T_(c) using a torus technique is listed,along with calorimetry measurements.

TABLE 6 Actual Composition T_(C) T_(C) T_(C) Alloy (% by weight, balanceFe) (EC) (EC) (EC) A₁ (EC) Designation Co Cr C Mn Si V Ti (torus)(calorimetry) (calculated) (calculated) TC1b 0.02 13.2 0.08 0.45 0.69 00.01 692 — 717 819 TC2 2.44 12.3 0.10 0.48 0.47 0 0.01 — — 742 793 TC34.81 12.3 0.10 0.48 0.46 0 0.01 — — 761 783 TC4 9.75 12.2 0.07 0.49 0.470 0.01 759/ — 793 765 682* TC5 9.80 12.2 0.10 0.48 0.46 1.02 0.01 — —795 790 TC6 7.32 12.3 0.12 0.29 0.46 0.89 0.46 754 752 775 813 TC7 7.4612.1 0.11 0.27 0.46 0.92 0 747 757 785 811 TC8 7.49 12.1 0.11 0.28 0.450 0 761 774 784 786 *Two values represent T_(C) during heating and T_(C)during subsequent cooling.

Modeling of Alloy Phase Behavior

Modeling of phase behavior for different improved alloy compositions todetermine compositions that contain increased amounts of phases thatcontribute positively to physical properties was performed. Compositionssuch as Cu, Z, M(C,N), M₂(C,N), and M₂₃C₆, may minimize the amount ofphases that are embrittling phases such as G, sigma, laves, and chi.There may be other reasons to include certain components. For example,silicon is typically included in stainless steel alloys to improveprocessing properties, and nickel and chromium are typically included inthe alloys to impart corrosion resistance. When two components may beincluded to accomplish the same result, then the less expensivecomponent may be beneficially included. For example, to the extentmanganese may be substituted for nickel without sacrificing performance,such a substitution may reduce the cost of the alloy at currentcomponent prices.

The effect of total phase content of the alloys similar to thosedescribed above has been found to be approximated by the equation:

σ_(r)=1.0235(TPC)+5.5603.  (EQN. 11)

Where σ_(r) is the creep rupture strength for one thousand hours at 800°C. in kilo-pound per square inch (ksi) and TPC is the total phasecontent calculated for the composition. This estimate was furtherimproved by only including in the TPC term the amount of Cu phase, Zphase, M(C,N) phase, M₂(C,N) phase, and M₂₃C₆ phase (the “desirablephases”), and calculating the constants on this basis. Anotherimprovement to this estimate may be to use only the difference betweenthe desirable phases present at the annealing temperature and at 800° C.Thus, the components that do not go into solution in the annealingprocess were not considered because they do not add significantly to thestrength of the alloys at elevated temperatures. For example, thedifference between the amount of Cu phase, Z phase, M(C,N) phase,M₂(C,N) phase, and M₂₃C₆ phase present based on equilibrium calculationsat annealing temperatures less the amount calculated to be present at800° C. may be 1% by weight of the alloy, or it could be 1.5% by weightof the alloy or 2% by weight of the alloy, to result in an alloy withgood high temperature strength. Further, the annealing temperature maybe 1200° C., or it may be 1250° C., or it may be 1300° C.

The improved alloys may be further understood by modeling the addition,or reduction, of different metals to determine the effect of changingamounts of that metal on the phase content of the alloy. For example,with a starting composition by weight of: 20% chromium, 3% copper, 4%manganese, 0.3% molybdenum, 0.8% niobium, 12.5% nickel, 0.5% silicon, 1%tungsten, 0.1% carbon and 0.25% elemental nitrogen, modeling withvarying amounts of chromium results in included phases of M₂₃C₆, M(C,N),M₂(C,N), Z, Cu, chi, laves, G, and sigma at 800° C., according to FIG.244. The amount of these phases plotted in each of FIGS. 244-254 is thecalculated amount of these phases at 800° C. In FIGS. 244-254, curve1398 refers to M₂₃C₆, curve 1400 refers to M₂(C,N) phase, curve 1402refers to Z phase, curve 1404 refers to Cu phase, curve 1406 refers tosigma phase, curve 1408 refers to chi phase, curve 1410 refers to Gphase, curve 1412 refers to laves phase, and curve 1414 refers to M(C,N)phase.

FIG. 244 depicts the weight percentages of phases versus weighpercentage of chromium in the alloy. As shown, the weight percentages ofphases 1398, 1400, 1402, and 1404 remained relatively constant from 20%by weight to 30% by weight of chromium, while sigma phase 1406 increasedlinearly above a chromium content of 20.5% by weight. Thus, from themodeling, a chromium content between 20% by weight and 20.5% by weightof the alloy may be favorable.

FIG. 245 depicts weight percentages of phases versus the weightpercentage of silicon (Si) in the alloy. As shown in FIG. 245, varyingthe silicon content of the alloy resulted in sigma phase 1406 appearingat levels above 1.2% by weight silicon and chi phase 1408 appearingabove a content of 1.4% by weight silicon. G phase 1410 appeared above1.6% by weight silicon and increased as the weight percent of siliconincreased. With increasing weight percentages of silicon, phases 1398,1400, and 1402, remained relatively constant and a slight increase in Cuphase 1404 was predicted. The appearance of sigma phase 1406, chi phase1408 and G phase 1410 indicates that a silicon content below 1.2% byweight in this alloy may be favorable.

FIG. 246 depicts weight percentage of phases formed versus weightpercentage of tungsten in the alloy. As shown in FIG. 246, varying theweight percentage of tungsten in the alloy resulted in sigma phase 1406appearing at 1.4% by weight tungsten. Laves phase 1412 appeared at 1.5%by weight tungsten and increased with increasing weight percentage oftungsten. Thus, the model predicts a tungsten content in this alloy ofbelow 1.3% by weight may be favorable.

FIG. 247 depicts weight percentage of phases formed verse the weightpercentage of niobium in the alloy. As shown in FIG. 247, modelingpredicted that weight percentage of Z phase 1402 increased in a linearfashion as the weight percentage of niobium increased in the alloy untilthe niobium content of the alloy reached 1.55% by weight. As the niobiumcontent increased from 0.1% by weight to 1.4% by weight, M₂(C,N) phase1400 decreased fairly linearly. The decrease in M₂(C,N) phase 1400 wascompensated for by the increase in Z phase 1402, Cu phase 1404 and M₂₃C₆phase 1398. Above 1.5% by weight niobium in the alloy, sigma phase 1406increased rapidly, Z phase 1402 decreased, M₂₃C₆ phase 1398 decreased,and M(C,N) phase 1414 appeared. Thus, the niobium content in the alloyof at most 1.5% by weight may maximize the weight percent of phases1398, 1400, 1402, and 1404 and avoid minimizing the weight percent ofsigma phase 1406 formed in the alloy. In order to make the alloyhot-workable, it was found that at least 0.5% by weight of niobium wasdesirable. Thus, in some embodiments, the alloy contains from 0.5% byweight to 1.5% by weight or from 0.8% by weight to 1% by weight niobium.

FIG. 248 depicts weight percentages of phases formed versus weightpercentage of carbon. As shown in FIG. 248, weight percentage of sigmaphase 1406 was predicted to decrease as the weight percentage of carbonin the alloy increased from 0 to 0.06. The weight percentage of M₂₃C₆phase 1398 was predicted to increase linearly as the weight percentageof carbon in the alloy increased to at most 0.5. M₂(C,N) phase 1400, Zphase 1402, and Cu phase 1404 was predicted to remain relativelyconstant as the weight percentage of carbon increased in the alloy.Since, sigma phase 1406 decreased after 0.06% by weight carbon, a carboncontent of 0.06% by weight to 0.2% weight in the alloy may bebeneficial.

FIG. 249 depicts weight percentage of phases formed versus weightpercentage of nitrogen. As shown in FIG. 249, the content of nitrogen inthe alloy increased from 0% by weight to 0.15% by weight, a content ofsigma phase 1406 decreased from 7% by weight to 0% by weight, a contentof M(C,N) phase 1414 decreased from 1% by weight to 0% by weight, acontent of M₂₃C6 phase 1398 increased from 0% by weight to 1.9% byweight, and a content of Z phase 1402 increased from 0% by weight to1.4% by weight. Above a nitrogen content of 0.15% by weight in thealloy, M₂(C,N) phase 1400 appeared and increased with as the content ofnitrogen in the alloy increases. Thus, a nitrogen content in a range of0.15% to 0.5% by weight in the alloy may be beneficial.

FIG. 250 depicts weight percentage of phases formed versus weightpercentage of titanium (Ti). As shown in FIG. 250, varying the weightpercentage of titanium from 0.19 to 1 may contribute to an increase in aweight percentage of sigma phase 1406 from 0 to 7.5 in the alloy. Thus,a titanium content of below 0.2% by weight in the alloy may bedesirable. As shown, as the content of titanium increased from 0% byweight to 0.2% by weight, an increase in the weight percentage of M(C,N)phase 1414 occurred, a decrease in the weight percentage of M₂(C,N)phase 1400 occurred, and a decrease in the weight percentage Z phase1402 occurred. The decreases in the amount of M₂(C,N) phase 1400 and Zphase 1402 appear to offset the increase in the weight percent of M(C,N)phase 1414. Thus, inclusion of Ti in the alloy may be for purposes otherthan for increasing the amount of phases that improve properties of thealloy.

FIG. 251 depicts weight percentage of phases formed versus weightpercentage of copper. As shown in FIG. 251, weight percentages of M₂₃C₆phase 1398, M₂(C,N) phase 1400, and Z phase 1402 did not varysignificantly as the weight percent of copper in the alloy increased.When the content of copper in the alloy increases above 2.5% by weight,Cu phase 1404 increased significantly. Thus, in some embodiments, it isdesirable to have more than 3% by weight copper in the alloy. In someembodiments, 10% by weight of copper in the alloy is beneficial.

FIG. 252 depicts weight percentage of phases formed versus weightpercentage of manganese. As shown in FIG. 252, varying the content ofmanganese in the alloy did not greatly affect the weight percentage ofbeneficial phases M₂₃C₆ phase 1398, M₂(C,N) phase 1400, Z phase 1402,and Cu phase 1404 in the alloy. The amount of manganese may therefore bevaried in order to reduce cost, or for other reasons, withoutsignificantly effecting the high temperature properties of the alloy,with an acceptable range of manganese content of the alloy being from 2%by weight to 10% by weight.

FIG. 253 depicts weight percentage of phases formed versus weightpercentage of nickel. As shown in FIG. 253, as the nickel content of thealloy increased above 8.4% by weight, a decrease in sigma phase 1406 wasobserved. As the Ni content of the alloy was increased from 8% by weightto 17% by weight, Cu phase 1404 decreased almost linearly until itdisappeared at 17% by weight and a small increase in the weightpercentage of M₂(C,N) phase 1400 was predicted. From the model, acontent of nickel of 10% by weight to 15% by weight in the alloy, or inother embodiments, a nickel content of 12% by weight to 13% by weight inthe alloy may avoid the formation of sigma phase 1406, whileimprovements in corrosion properties offset any detrimental effect ofless Cu phase 1404.

FIG. 254 depicts weight percentage of phases formed versus weightpercentage of molybdenum. As shown in FIG. 254, the weight percentage ofbeneficial phases M₂₃C₆ phase 1398, M₂(C,N) phase 1400, Z phase 1402,and Cu phase 1404 remained relatively constant as the weight percentageof molybdenum in the alloy was varied. As Mo content of the alloyexceeded 0.65% by weight, the weight percentages of sigma phase 1406 andchi phase 1408 in the alloy increased significantly with no significantchanges in the other phases. The content of molybdenum in the alloy, insome embodiments, may therefore be limited to at most 0.5% by weight.

Alloy Examples

Alloys A through N were prepared according to TABLE 7. Measuredcompositions are included in the TABLE 7 when such measurements areavailable. The total phase content of the alloys is calculated for thelisted composition.

TABLE 7 % by weight 800° C. Total Alloy Cr Cu Mn Mo Nb Ni Si W C N TiPhase A Target 20 — 4 0.3 0.8 12.5 0.5 — 0.09 0.25 — Actual^(b) 19 — 4.20.3 0.8 12.5 0.5 — 0.09 0.24 — 3.35^(a) B Target 20 3 4 0.3 0.8 13 0.5 10.09 0.25 — Actual-1^(b) 20 3 4 0.3 0.77 13 0.5 1 0.09 0.26 — 4.40^(a)Actual-2^(b) 20.35 2.94 4.09 0.28 0.76 12.52 0.44 1.03 0.09 0.23 —Actual- 18.78 2.94 2.85 0.29 0.65 12.75 0.39 1.03 0.10 0.23 0.0043^(b,c) C Target 20 4.5 4 0.3 0.8 12.5 0.5 1 0.15 0.25 — 7.15Actual-1^(b) 18.74 4.37 3.68 0.29 0.77 13.00 0.43 1.18 0.11 0.17 0.0025.45 Actual- 20.48 4.75 4.13 0.30 0.07 12.81 0.52 1.18 0.17 0.14 0.016.23 2^(c,b) D Target 20 4.5 4 0.3 0 12.5 0.5 1 0.2 0.5 0 10 E Target 204 4 0.5 0.8 12.5 0.5 1 0.1 0.3 — 6.2 Actual 18.84 4.34 3.65 0.29 0.7512.93 0.43 1.21 0.09 0.2 0.002 5.3 F Target 20 3 1 0.3 0.77 13 0.5 10.09 0.26 — 4.7 Actual^(b) 18.97 2.88 0.92 0.29 0.74 13.25 0.43 1.170.05 0.12 <0.001 2.45 G Target 20 4.5 4 0.3 0.8 7 0.5 1 0.2 0.5 —Actual^(e) 20.08 4.36 4 0.3 0.81 7.01 0.5 1.04 0.24 0.31 0.008 9.6^(a) HTarget 21 3 3 0.3 0.80 7 1 2 0.1 0.4 — Actual^(e) 21.1 2.95 3.01 0.310.82 6.98 0.51 2.06 0.13 0.32 <0.001 13.46^(f) I Target 21 3 8 0.3 0.807 0.5 1 0.1 0.5 — 7.1 Actual^(e) 21.31 2.94 7.95 0.31 0.83 7.02 0.521.05 0.13 0.37 0.003 9.45 J Target 20 4 2 0.5 1.00 12.5 1 1 0.20 0.50 —9.8 Actual^(e) 19.93 3.85 2.13 0.5 0.99 12.11 1.08 1.01 0.23 0.29 0.0228.95 K Target 20 3 4 0.3 0.77 13 0.5 1 0.09 0.26 — Actual^(e) 18.94 2.964.01 0.31 0.81 13.05 0.52 1.03 0.12 0.35 0.018 5.62 L Target 20 3 4 0.30.10 13 0.5 1 0.09 0.26 — Actual^(b) 20.06 2.96 3.95 0.3 0.12 12.93 0.591.03 0.11 0.25 0.005 4.28 M Target 20 3 4 0.3 0.50 13 0.5 1 0.09 0.26 —Actual^(b) 20.11 2.93 3.98 0.3 0.51 12.94 0.5 1.03 0.12 0.13 <0.001 2.76N Target 20 3.4 4 1 0.80 12.5 0.5 2 0.1 0.3 8.85^(g) ^(a)Calculatedusing actual composition; ^(b)Nonconsumable-arc melted; ^(c)Remelted byelement compensation; ^(d)Contains 1.7% sigma phase and 1.55% lavesphase; ^(e)Induction melted; ^(f)Contains 3.9% sigma phase and 1.7% chiphase; ^(g)Includes 1.7% sigma and 1.55% laves phases.Hot working with Niobium Example

To determine the capability for alloys to be hot worked, samples ofalloys C, D, E, F, K, L, and M in TABLE 7 were prepared by arc-meltingone pound samples into ingots of 25.4 millimeter×25.4 millimeter×101.6millimeter (1 inch×1 inch×4 inch). After cutting hot-tops and removingsome shrinkage underneath, each sample was homogenized at 1200° C. forone hour, and then hot-rolled to a thickness of 12.7 millimeter (0.5inch) at 1200° C. with intermediate heat. The samples were then coldrolled to a 6.34 millimeter (0.25 inch) thick plate and vacuum annealedat 1200° C. for one hour.

When alloy D (0% by weight niobium) was hot rolled, it cracked and therolling to 12.7 millimeter (0.5 inch) thickness could not beaccomplished. Alloy L (0.12% by weight niobium) could be hot-rolled, butdeveloped cracks from the edge of the samples progressing toward thecenter of the sample, and would not be a useful material after such hotrolling. Alloy M (0.51% Nb) could be hot-rolled, without developingcracks or any other problems. The other samples were processed using theabove described procedure without any problems, resulting in 6.35millimeter (0.25 inch) plates that were free of cracks. It has beenfound that even 0.07% by weight niobium in the alloy composition maysignificantly reduce the tendency of the alloy to develop cracks duringhot working. An alloy having at lest 0.5% by weight niobium can beincorporated in wrought alloys to improve properties such as hotworkability. Some alloys may have by weight from 0.5% o 1.2% niobium,from 0.6% to 1.0% niobium, or from 0.7% to 0.9% niobium to improve thealloy properties.

High Temperature Heat Treating Example

Samples of alloys A and B from TABLE 7 were processed by two differentmethods. Process A included a heat treating and an annealing step at atemperature of 1200° C. Process B included a heat treating and anannealing step at a temperature of 1250° C. With the higher heattreating and annealing temperatures, measurable improvements in yieldstrength and ultimate tensile strength were observed for the two alloyswhen processed at the higher temperature.

The process at a temperature of 1200° C. was accomplished as follows:sections of 15.24 cm (six inch) ID by 3.81 cm (1.5 inches) thickcentrifugally cast pipe were homogenized at a temperature of 1200° C.for one and a half hours; a section was then hot-rolled at 1200° C. to a25.4 cm (one inch) thickness for alloy A and a 1.91 cm (three-quarterinch) thickness for alloy B; after cooling to room temperature, theplates were annealed at 1200° C. for fifteen minutes; the plates werethen cold-rolled to a thickness of 13.97 millimeter (0.55 inches). Thecold-rolled plates were annealed for one hour at 1200° C. in air underan argon blanket. The annealed plates were annealed for a final time at1250° C. for one hour in air under an argon blanket. This process isreferred to herein as process A.

The process with higher heat treating and annealing temperatures variedfrom the above procedure by homogenization of the cast plates at atemperature of 1250° C. for three hours instead of one and a half hours;hot rolling was carried out at 1200° C. from a 38.1 millimeter (1.5inch) thickness to a 19.05 millimeter (0.75 inch) thickness; and theresulting plate was annealed for fifteen minute at 1200° C. followed bycold-rolling to 13.97 millimeter (0.55 inch) thickness. This process isreferred to herein as process B.

FIGS. 255A-255E depict yield strengths and ultimate tensile strengthsfor different metals. In FIG. 255A, data 1416 shows yield strength anddata 1418 shows ultimate tensile strength for alloy A treated by processA. Data 1420 shows yield strength and data 1422 shows ultimate tensilestrength for alloy B treated by process B. Data 1424 shows yieldstrength and data 1426 shows ultimate tensile strength for 347Hstainless steel.

In FIG. 255B, data 2214 show yield strength of alloy G treated byprocess A. Data 2216 and 2218 show yield strength for alloys H and I.Data 2220 shows yield strength of alloy B treated by process A. Data2222 shows yield strength of alloy B treated by process B. Data 1424shows yield strength for 347H stainless steel.

In FIG. 255C, data 2224 show ultimate tensile strength of alloy Gtreated by process A. Data 2226 and 2228 show ultimate tensile strengthfor alloys H and I. 2230 shows ultimate tensile strength of alloy Btreated by process A. Data 2232 shows ultimate tensile strength of alloyB treated by process B. Data 1426 shows ultimate tensile strength for347H stainless steel.

In FIG. 255D, data 2234 and 2236 show yield strength for alloys J and K.Data 2220 shows yield strength of alloy B treated by process A. Data2222 shows yield strength of alloy B treated by process B. Data 1424shows yield strength for 347H stainless steel.

In FIG. 255E data 2238 and 2240 show ultimate tensile strength foralloys J and K. Data 2230 shows ultimate tensile strength of alloy Btreated by process A. Data 2232 shows ultimate tensile strength of alloyB treated by process B. Data 1426 shows ultimate tensile strength for347H stainless steel.

Both ultimate tensile strength and yield strength were greater for thealloys treated at higher temperatures as compared to 347H stainlesssteel. A considerable improvement over 347H can be seen for alloys A, B,G, H, I, J, and K. For example, alloys A, B, G, H, I, J, and K retainedtensile properties to test temperatures of 1000° C. For an applicationwhere yield strength of 20 ksi was needed, alloys A, B, G, H, I, J, andK provide the needed yield strength for at least an additional 250° C.For a 5 ksi difference between yield and ultimate tensile strength attest temperatures, alloys A, B, G, H, I, J, and K may be used attemperatures of 950° C. and 1000° C. as opposed to only 870° C. for347H.

Samples of Alloy B, treated by process A and by process B were subjectedto stress-rupture tests and the results are tabulated in TABLE 8. It canbe seen from Table 8 that process B, with a higher annealingtemperature, resulted in 47% to 474% improvement in time to rupture.

TABLE 8 Temperature Stress Process A life Process B life Improvement (°C.) (MPa) (hours) (hours) by Process B 800 100 164.2 241.6 47% 850 70 32151.7 474% 850 55 264.1 500.7 90% 900 42 90.1 140.1 55%

High Temperature Yield After Cold Work and Aging Example

A sample of alloy B, processed by process B, was aged at 750° C. for1000 hours after being cold worked by 2.5%, 5%, and 10%, and withoutcold working. After aging, each was tested for tensile strength andyield strength at 750° C. Results are tabulated in TABLE 9. It can beseen from TABLE 9 that the yield strength increased significantly as aresult of cold work and high temperature aging. The ultimate tensilestrength at 750° C. decreased only slightly as a result of the hightemperature aging and cold working. The annealed only sample and theaged only sample were also tested at room temperature for yield strengthand ultimate tensile strength. The yield strength at room temperatureincreased from 307 MPa to 318 MPa as a result of the aging. The ultimatetensile strength decreased from 720 MPa to 710 MPa as a result of thehigh temperature aging.

TABLE 9 2.5% Cold 5% Cold 10% Cold Worked Worked and Worked and AnnealedAged and aged aged aged Yield 170 212 235 290 325 Strength, MPa Ultimate372 358 350 360 358 Tensile Strength, MPa

These characteristics may be compared to competing alloys, such as 347H,which significantly lose high temperature properties as a result ofonly, for example, 10% cold work. Because fabrication of tubulars andheaters useful in an in situ heat treatment process often require coldwork for their fabrication, improvement of some high temperatureproperties, or at least lack of significant loss of high temperatureproperties may be a significant advantage for alloys having thesecharacteristics. It may be particularly advantageous when theseproperties are improved, or at least not significantly decreased, byhigh temperature aging.

Creep Example

Samples of alloys were subjected to 100 MPa stress at 800° C. in anitrogen with 0.1% oxygen test environment. Each of the samples wasfirst annealed for one hour at 1200° C. TABLE 10 shows the time torupture, elongation at rupture, and total phase content, where the totalphase content is known.

TABLE 10 Total Phase Rupture time Elongation Content % at Alloy (hr) (%)800° C. Comments B 283 7.6 4.4 B 116 5.6 4.4 B 127 3.9 4.4 10% cold workB 228 3.1 4.4 10% cold work B 185 2.3 4.4 Laser weld C 60 5.3 5.45 C 1373.6 5.45 Repeated test E 165 5.1 5.3 F 24 6.6 2.45 G 178 11.3 9.6 H 1839.8 13.46 total 7.86 good phases I 228 12.6 9.45 J 240 19.7 8.95 K 12314.2 5.62 N 147 7.4 8.85 347H 1.87 92 0.75 As received 347H 2.1 61 0.75As received NF709 56 32 Annealed NF709 30 29.4 NF709 36 26 Cold Strain10% NF709 82 30.6 Cold Strain 10% NF709 700 16.2 Cold Strain 15% NF709643 11.4 Cold Strain 20% NF709 1084 6 Cold Strain 20% NF709 754 37.6 Asreceived

A sample of the improved alloy B was processed and rolled into a tube.The seam was welded to form a 31.75 millimeter (1.25 inch) OD pipe. Thepipe was then cut and welded back together in order to test the strengthof the weld. The filler metal was ERNiCrMo-3, and the weld was completedwith argon shielding gas and three passes with a preheat minimumtemperature of 50° C. and an interpass maximum temperature of 350° C.Creep failure was tested for the segment of welded pipe at 44.8 MPa and900° C. A rupture time of 41 hours was measured with failure at a strainof 5.5%. This demonstrated that the weld, including the heat affectedzone around the weld, was not significantly weaker than the base alloy.

Metal Sulfidation Example

FIG. 256 depicts projected corrosion rates (metal loss per year) over aone-year period for several metals in a sulfidation atmosphere. Themetals were exposed to a gaseous mixture containing about 1% by volumecarbon monoxide sulfide (COS), about 32% by volume carbon monoxide (CO)and about 67% volume CO₂ at 538° C. (1000° F.), at 649° C. (1200° C.),at 760° C. (1400° F.), and at 871° C. (about 1600° F.) for 384 hours.The resulting data was extrapolated to a one-year time period. Theexperimental conditions simulates in-situ sub-surface formationsulfidation conditions of 10% H₂ by volume, 10% H₂S by volume and 25%H₂O by volume at 870° C. Curve 1428 depicts 625 stainless steel. Curve1430 depicts CF8C+ stainless steel. Curve 1432 depict data for 410stainless steel. Curve 1434 depicts 20 25 Nb stainless steel. Curve 1436depicts 253 MA stainless steel. Curve 1438 depicts 347H stainless steel.Curve 1440 depicts 446 stainless steel. 410 stainless steel exhibits adecrease in corrosion at temperatures between about 500° C. and about650° C.

In some embodiments, cobalt is added to 410 stainless steel to decreasethe rate of corrosion at elevated temperatures (for example,temperatures greater than 1200° F.) relative to untreated 410 stainlesssteel. Addition of cobalt to 410 stainless steel may enhance thestrength of the stainless steel at high temperatures (for example,temperatures greater than 1200° F., greater than 1400° F., greater than1500° F., or greater than 1600° F.) and/or change the magneticcharacteristics of the metal. FIG. 257 depicts projected corrosion rates(metal loss per year) for 410 stainless steel and 410 stainless steelcontaining various amounts of cobalt in a sulfidation atmosphere. Themetals were exposed to the same conditions as the metals in FIG. 257.Bars 1442 depicts data for 410 stainless steel. Bar 1444 depicts datafor 410 stainless steel with 2.5% cobalt by weight. Bar 1446 depictsdata for 410 stainless steel with 5% cobalt by weight. Bar 1448 depictsdata for 410 stainless steel with 10% cobalt by weight. As shown in FIG.257, as the amount of cobalt in the 410 stainless steel increases, thecorrosion rate in a sulfidation atmosphere decreases relative tonon-cobalt containing 410 stainless steel in a temperature range ofabout 800° C. to about 880° C.

Varying Heater Output Simulation

A STARS simulation determined heating properties using temperaturelimited heaters with varying power outputs. FIG. 258 depicts an exampleof richness of an oil shale formation (gal/ton) versus depth (ft). Upperportions of the formation (above about 1210 feet) tend to have a leanerrichness, lower water-filled porosity, and/or less dawsonite than deeperportions of the formation. For the simulation, a heater similar to theheater depicted in FIG. 43 was used. Portion 550 had a length of 368feet above the dashed line shown in FIG. 258 and portion 548 had alength of 587 feet below the dashed line.

In the first example, the temperature limited heater had constantthermal properties along the entire length of the heater. The heaterincluded a 14.34 millimeter (0.565 inch) diameter copper core with acarbon steel conductor (Curie temperature of 1418° F., pure iron withoutside diameter of 20.955 millimeter (0.825 inch)) surrounding thecopper core. The outer conductor was 347H stainless steel surroundingthe carbon steel conductor with an outside diameter of 31.75 millimeter(1.2 inch). The resistance per foot (mΩ/ft) versus temperature (° F.)profile of the heater is shown in FIG. 259. FIG. 260 depicts averagetemperature in the formation (° F.) versus time (days) as determined bythe simulation for the first example. Curve 1450 depicts averagetemperature versus time for the top portion of the formation. Curve 1452depicts average temperature versus time for the entire formation. Curve1454 depicts average temperature versus time for the bottom portion ofthe formation. As shown, the average temperature in the bottom portionof the formation lagged behind the average temperature in the topportion of the formation and the entire formation. The top portion ofthe formation reached an average temperature of 340° C. (644° F.) in1584 days. The bottom portion of the formation reached an averagetemperature of 340° C. (644° F.) in 1922 days. Thus, the bottom portionlagged behind the top portion by almost a year to reach an averagetemperature near a pyrolysis temperature.

In the second example, portion 550 of the temperature limited heater hadthe same properties used in the first example. Portion 548 of the heaterwas altered to have a Curie temperature of 843° C. (1550° F.) by theaddition of cobalt to the iron conductor. FIG. 261 depicts resistanceper foot (mΩ/ft) versus temperature (° F.) for the second heaterexample. Curve 1456 depicts the resistance profile for the top portion(portion 550). Curve 1458 depicts the resistance profile for the bottomportion (portion 548). FIG. 262 depicts average temperature in theformation (° F.) versus time (days) as determined by the simulation forthe second example. Curve 1460 depicts average temperature versus timefor the top portion of the formation. Curve 1462 depicts averagetemperature versus time for the entire formation. Curve 1464 depictsaverage temperature versus time for the bottom portion of the formation.As shown, the average temperature in the bottom portion of the formationlagged behind the average temperature in the top portion of theformation and the entire formation. The top portion of the formationreached an average temperature of 340° C. (644° F.) in 1574 days. Thebottom portion of the formation reached an average temperature of 340°C. (644° F.) in 1701 days. Thus, the bottom portion still lagged behindthe top portion to reach an average temperature near a pyrolysistemperature but the time lag was less than the time lag in the firstexample.

FIG. 263 depicts net heater energy input (Btu) versus time (days) forthe second example. Curve 1466 depicts net heater energy input for thebottom portion. Curve 1468 depicts net heater input for the top portion.The net heater energy input to reach a temperature of 340° C. (644° F.)for the bottom portion was 2.35×10¹⁰ Btu. The net heater energy input toreach a temperature of 340° C. (644° F.) for the top portion was1.32×10¹⁰ Btu. Thus, it took 12% more power to reach the desiredtemperature in the bottom portion.

FIG. 264 depicts power injection per foot (W/ft) versus time (days) forthe second example. Curve 1470 depicts power injection rate for thebottom portion. Curve 1472 depicts power injection rate for the topportion. The power injection rate for the bottom portion was about 6%more than the power injection rate for the top portion. Thus, eitherreducing the power output of the top portion and/or increasing the poweroutput of the bottom portion to a total of about 6% should provideapproximately similar heating rates in the top and bottom portions.

In the third example, dimensions of the top portion (portion 550) werealtered to provide less power output. Portion 550 was adjusted to have acopper core with an outside diameter of 13.84 millimeter (0.545 inch), acarbon steel conductor with an outside diameter of 17.78 millimeter(0.700 inch) surrounding the copper core, and an outer conductor of 347Hstainless steel with an outside diameter of 30.48 millimeter (1.2 inch)surrounding the carbon steel conductor. The bottom portion (portion 548)had the same properties as the heater in the second example. FIG. 265depicts resistance per foot (mΩ/ft) versus temperature (° F.) for thethird heater example. Curve 1474 depicts the resistance profile for thetop portion (portion 550). Curve 1476 depicts the resistance profile ofthe top portion in the second example. Curve 1478 depicts the resistanceprofile for the bottom portion (portion 548). FIG. 266 depicts averagetemperature in the formation (° F.) versus time (days) as determined bythe simulation for the third example. Curve 1480 depicts averagetemperature versus time for the top portion of the formation. Curve 1482depicts average temperature versus time for the bottom portion of theformation. As shown, the average temperature in the bottom portion ofthe formation was approximately the same as the average temperature inthe top portion of the formation, especially after a time of about 1000days. The top portion of the formation reached an average temperature of340° C. (644° F.) in 1642 days. The bottom portion of the formationreached an average temperature of 340° C. (644° F.) in 1649 days. Thus,the bottom portion reached an average temperature near a pyrolysistemperature only 5 days later than the top portion.

FIG. 267 depicts cumulative energy injection (Btu) versus time (days)for each of the three heater examples. Curve 1484 depicts cumulativeenergy injection for the first heater example. Curve 1486 depictscumulative energy injection for the second heater example. Curve 1488depicts cumulative energy injection for the third heater example. Thesecond and third heater examples have nearly identical cumulative energyinjections. The first heater example had a cumulative energy injectionabout 7% higher to reach an average temperature of 340° C. (644° F.) inthe bottom portion.

FIGS. 258-267 depict results for heaters with a 40 foot spacing betweenheaters in a triangular heating pattern. FIG. 268 depicts averagetemperature (° F.) versus time (days) for the third heater example witha 30 foot spacing between heaters in the formation as determined by thesimulation. Curve 1490 depicts average temperature versus time for thetop portion of the formation. Curve 1492 depicts average temperatureversus time for the bottom portion of the formation. The curves in FIG.268 still tracked with approximately equal heating rates in the top andbottom portions. The time to reach an average temperature in theportions was reduced. The top portion of the formation reached anaverage temperature of 340° C. (644° F.) in 903 days. The bottom portionof the formation reached an average temperature of 340° C. (644° F.) in884 days. Thus, the reduced heater spacing decreases the time needed toreach an average selected temperature in the formation.

As a fourth example, the STARS simulation was used to determine heatingproperties of temperature limited heaters with varying power outputswhen using the temperature limited heaters in the heater configurationand pattern depicted in FIGS. 70 and 72. The heater pattern had a 30foot heater spacing. Portion 550 had a length of 368 feet and portion548 had a length of 587 feet as in the previous examples. Portion 550included a solid 410 stainless steel conductor with an outside diameterof 31.75 millimeter (1.25 inch). Portion 548 included a solid 410stainless steel conductor with 9% by weight cobalt added. The Curietemperature of portion 548 is 110° C. (230° F.) higher than the Curietemperature of portion 550.

FIG. 269 depicts average temperature (° F.) versus time (days) for thefourth heater example using the heater configuration and patterndepicted in FIGS. 70 and 72 as determined by the simulation. Curve 1494depicts average temperature versus time for the top portion of theformation. Curve 1496 depicts average temperature versus time for thebottom portion of the formation. The curves in FIG. 269 showapproximately equal heating rates in the top and bottom portions. Thetop portion of the formation reached a temperature of 340° C. (644° F.)in 859 days. The bottom portion of the formation reached a temperatureof 340° C. (644° F.) in 880 days. In this heater configuration andheater pattern, the top portion of the formation reached a selectedtemperature at about the same time as a bottom portion of the formation.

Tar Sands Simulation

A STARS simulation was used to simulate heating of a tar sands formationusing the heater well pattern depicted in FIG. 130. The heaters had ahorizontal length in the tar sands formation of 600 m. The heating rateof the heaters was about 750 W/m. Production well 206B, depicted in FIG.130, was used at the production well in the simulation. The bottom holepressure in the horizontal production well was maintained at about 690kPa. The tar sands formation properties were based on Athabasca tarsands. Input properties for the tar sands formation simulation included:initial porosity equals 0.28; initial oil saturation equals 0.8; initialwater saturation equals 0.2; initial gas saturation equals 0.0; initialvertical permeability equals 250 millidarcy; initial horizontalpermeability equals 500 millidarcy; initial Kv/Kh equals 0.5;hydrocarbon layer thickness equals 28 m; depth of hydrocarbon layerequals 587 m; initial reservoir pressure equals 3771 kPa; distancebetween production well and lower boundary of hydrocarbon layer equals2.5 meter; distance of topmost heaters and overburden equals 9 meter;spacing between heaters equals 9.5 meter; initial hydrocarbon layertemperature equals 18.6° C.; viscosity at initial temperature equals 53Pa·s (53000 cp); and gas to oil ratio (GOR) in the tar equals 50standard cubic feet/standard barrel. The heaters were constant wattageheaters with a highest temperature of 538° C. at the sand face and aheater power of 755 W/m. The heater wells had a diameter of 15.2 cm.

FIG. 270 depicts a temperature profile in the formation after 360 daysusing the STARS simulation. The hottest spots are at or near heaters716. The temperature profile shows that portions of the formationbetween the heaters are warmer than other portions of the formation.These warmer portions create more mobility between the heaters andcreate a flow path for fluids in the formation to drain downwardstowards the production wells.

FIG. 271 depicts an oil saturation profile in the formation after 360days using the STARS simulation. Oil saturation is shown on a scale of0.00 to 1.00 with 1.00 being 100% oil saturation. The oil saturationscale is shown in the sidebar. Oil saturation, at 360 days, is somewhatlower at heaters 716 and production well 206B. FIG. 272 depicts the oilsaturation profile in the formation after 1095 days using the STARSsimulation. Oil saturation decreased overall in the formation with agreater decrease in oil saturation near the heaters and in between theheaters after 1095 days. FIG. 273 depicts the oil saturation profile inthe formation after 1470 days using the STARS simulation. The oilsaturation profile in FIG. 273 shows that the oil is mobilized andflowing towards the lower portions of the formation. FIG. 274 depictsthe oil saturation profile in the formation after 1826 days using theSTARS simulation. The oil saturation is low in a majority of theformation with some higher oil saturation remaining at or near thebottom of the formation in portions below production well 206B. This oilsaturation profile shows that a majority of oil in the formation hasbeen produced from the formation after 1826 days.

FIG. 275 depicts the temperature profile in the formation after 1826days using the STARS simulation. The temperature profile shows arelatively uniform temperature profile in the formation except atheaters 716 and in the extreme (corner) portions of the formation. Thetemperature profile shows that a flow path has been created between theheaters and to production well 206B.

FIG. 276 depicts oil production rate 1498 (bbl/day)(left axis) and gasproduction rate 1500 (ft³/day)(right axis) versus time (years). The oilproduction and gas production plots show that oil is produced at earlystages (0-1.5 years) of production with little gas production. The oilproduced during this time was most likely heavier mobilized oil that isunpyrolyzed. After about 1.5 years, gas production increased sharply asoil production decreased sharply. The gas production rate quicklydecreased at about 2 years. Oil production then slowly increased up to amaximum production around about 3.75 years. Oil production then slowlydecreased as oil in the formation was depleted.

From the STARS simulation, the ratio of energy out (produced oil and gasenergy content) versus energy in (heater input into the formation) wascalculated to be about 12 to 1 after about 5 years. The total recoverypercentage of oil in place was calculated to be about 60% after about 5years. Thus, producing oil from a tar sands formation using anembodiment of the heater and production well pattern depicted in FIG.130 may produce high oil recoveries and high energy out to energy inratios.

Tar Sands Example

A STARS simulation was used in combination with experimental analysis tosimulate an in situ heat treatment process of a tar sands formation.Heating conditions for the experimental analysis were determined fromreservoir simulations. The experimental analysis included heating a cellof tar sands from the formation to a selected temperature and thenreducing the pressure of the cell (blow down) to 100 psig. The processwas repeated for several different selected temperatures. While heatingthe cells, formation and fluid properties of the cells were monitoredwhile producing fluids to maintain the pressure below an optimumpressure of 12 MPa before blow down and while producing fluids afterblow down (although the pressure may have reached higher pressures insome cases, the pressure was quickly adjusted and does not affect theresults of the experiments). FIGS. 277-284 depict results from thesimulation and experiments.

FIG. 277 depicts weight percentage of original bitumen in place(OBIP)(left axis) and volume percentage of OBIP (right axis) versustemperature (° C.). The term “OBIP” refers, in these experiments, to theamount of bitumen that was in the laboratory vessel with 100% being theoriginal amount of bitumen in the laboratory vessel. Plot 2152 depictsbitumen conversion (correlated to weight percentage of OBIP). Plot 2152shows that bitumen conversion began to be significant at about 270° C.and ended at about 340° C. The bitumen conversion was relatively linearover the temperature range.

Plot 2154 depicts barrels of oil equivalent from producing fluids andproduction at blow down (correlated to volume percentage of OBIP). Plot2156 depicts barrels of oil equivalent from producing fluids (correlatedto volume percentage of OBIP). Plot 2158 depicts oil production fromproducing fluids (correlated to volume percentage of OBIP). Plot 2160depicts barrels of oil equivalent from production at blow down(correlated to volume percentage of OBIP). Plot 2162 depicts oilproduction at blow down (correlated to volume percentage of OBIP). Asshown in FIG. 277, the production volume began to significantly increaseas bitumen conversion began at about 270° C. with a significant portionof the oil and barrels of oil equivalent (the production volume) comingfrom producing fluids and only some volume coming from the blow down.

FIG. 278 depicts bitumen conversion percentage (weight percentage of(OBIP))(left axis) and oil, gas, and coke weight percentage (as a weightpercentage of OBIP)(right axis) versus temperature (0° C.). Plot 2164depicts bitumen conversion (correlated to weight percentage of OBIP).Plot 2166 depicts oil production from producing fluids correlated toweight percentage of OBIP (right axis). Plot 2168 depicts cokeproduction correlated to weight percentage of OBIP (right axis). Plot2170 depicts gas production from producing fluids correlated to weightpercentage of OBIP (right axis). Plot 2172 depicts oil production fromblow down production correlated to weight percentage of OBIP (rightaxis). Plot 2174 depicts gas production from blow down productioncorrelated to weight percentage of OBIP (right axis). FIG. 278 showsthat coke production begins to increase at about 280° C. and maximizesaround 340° C. FIG. 278 also shows that the majority of oil and gasproduction is from produced fluids with only a small fraction from blowdown production.

FIG. 279 depicts API gravity (°)(left axis) of produced fluids, blowdown production, and oil left in place along with pressure (psig)(rightaxis) versus temperature (0° C.). Plot 2176 depicts API gravity ofproduced fluids versus temperature. Plot 2178 depicts API gravity offluids produced at blow down versus temperature. Plot 2180 depictspressure versus temperature. Plot 2182 depicts API gravity of oil(bitumen) in the formation versus temperature. FIG. 279 shows that theAPI gravity of the oil in the formation remains relatively constant atabout 100 API and that the API gravity of produced fluids and fluidsproduced at blow down increases slightly at blow down.

FIGS. 280A-D depict gas-to-oil ratios (GOR) in thousand cubic feet perbarrel ((Mcf/bbl)(y-axis) versus temperature (° C.)(x-axis) fordifferent types of gas at a low temperature blow down (about 277° C.)and a high temperature blow down (at about 290° C.). FIG. 280A depictsthe GOR versus temperature for carbon dioxide (CO₂). Plot 2184 depictsthe GOR for the low temperature blow down. Plot 2186 depicts the GOR forthe high temperature blow down. FIG. 280B depicts the GOR versustemperature for hydrocarbons. FIG. 280C depicts the GOR for hydrogensulfide (H₂S). FIG. 280D depicts the GOR for hydrogen (H₂). In FIGS.280B-D, the GORs were approximately the same for both the lowtemperature and high temperature blow downs. The GORs for CO₂ (shown inFIG. 280) was different for the high temperature blow down and the lowtemperature blow down. The reason for the difference in the GORs for CO₂may be that CO₂ was produced early (at low temperatures) by the hydrousdecomposition of dolomite and other carbonate minerals and clays. Atthese low temperatures, there was hardly any produced oil so the GOR isvery high because the denominator in the ratio is practically zero. Theother gases (hydrocarbons, H₂S, and H₂) were produced concurrently withthe oil either because they were all generated by the upgrading ofbitumen (for example, (hydrocarbons, H₂, and oil) or because they weregenerated by the decomposition of minerals (such as pyrite) in the sametemperature range as that of bitumen upgrading. Thus, when the GOR wascalculated, the denominator (oil) was non zero for hydrocarbons, H₂S,and H₂.

FIG. 281 depicts coke yield (weight percentage)(y-axis) versustemperature (° C.)(x-axis). Plot 2188 depicts bitumen and kerogen cokeas a weight percent of original mass in the formation. Plot 2190 depictsbitumen coke as a weight percent of original bitumen in place (OBIP) inthe formation. FIG. 281 shows that kerogen coke is already present at atemperature of about 260° C. (the lowest temperature cell experiment)while bitumen coke begins to form at about 280° C. and maximizes atabout 340° C.

FIGS. 282A-D depict assessed hydrocarbon isomer shifts in fluidsproduced from the experimental cells as a function of temperature andbitumen conversion. Bitumen conversion and temperature increase fromleft to right in the plots in FIGS. 282A-D with the minimum bitumenconversion being 10%, the maximum bitumen conversion being 100%, theminimum temperature being 277° C., and the maximum temperature being350° C. The arrows in FIGS. 282A-D show the direction of increasingbitumen conversion and temperature.

FIG. 282A depicts the hydrocarbon isomer shift of n-butane-δ¹³C₄percentage (y-axis) versus propane-δ¹³C₃ percentage α-axis). FIG. 282Bdepicts the hydrocarbon isomer shift of n-pentane-δ¹³C₅ percentage(y-axis) versus propane-δ¹³C₃ percentage (x-axis). FIG. 282C depicts thehydrocarbon isomer shift of n-pentane-δ¹³C₅ percentage (y-axis) versusn-butane-δ¹³C₄ percentage (x-axis). FIG. 282D depicts the hydrocarbonisomer shift of i-pentane-δ¹³C₅ percentage (y-axis) versusi-butane-δ¹³C₄ percentage (x-axis). FIGS. 282A-D show that there is arelatively linear relationship between the hydrocarbon isomer shifts andboth temperature and bitumen conversion. The relatively linearrelationship may be used to assess formation temperature and/or bitumenconversion by monitoring the hydrocarbon isomer shifts in fluidsproduced from the formation.

FIG. 283 depicts weight percentage (Wt %)(y-axis) of saturates from SARAanalysis of the produced fluids versus temperature (° C.)(x-axis). Thelogarithmic relationship between the weight percentage of saturates andtemperature may be used to assess formation temperature by monitoringthe weight percentage of saturates in fluids produced from theformation.

FIG. 284 depicts weight percentage (Wt %)(y-axis) of n-C₇ of theproduced fluids versus temperature (° C.)(x-axis). The linearrelationship between the weight percentage of n-C₇ and temperature maybe used to assess formation temperature by monitoring the weightpercentage of n-C₇ in fluids produced from the formation.

Pre-Heating Using Heaters For Injectivity Before Steam Drive Example

An example uses the embodiment depicted in FIGS. 134 and 135 to preheat.Injection wells 748 and production wells 206 are substantially verticalwells. Heaters 716 are long substantially horizontal heaters positionedso that the heaters pass in the vicinity of injection wells 748. Heaters716 intersect the vertical well patterns slightly displaced from thevertical wells.

The following conditions were assumed for purposes of this example:

(a) heater well spacing; s=330 ft;

(b) formation thickness; h=100 ft;

(c) formation heat capacity; ρc=35 BTU/cu. ft.-° F.

(d) formation thermal conductivity; λ=1.2 BTU/ft-hr-° F.;

(e) electric heating rate; q_(h)=200 watts/ft;

(f) steam injection rate; q_(s)=500 bbls/day;

(g) enthalpy of steam; h_(s)=1000 BTU/lb;

(h) time of heating; t=1 year;

(i) total electric heat injection; Q_(E)=BTU/pattern/year;

(j) radius of electric heat; r=ft; and

(k) total steam heat injected; Q_(s)=BTU/pattern/year.

Electric heating for one well pattern for one year is given by:

Q _(E) =q _(h) ·t·s(BTU/pattern/year);  (EQN. 12)

with Q_(E)=(200 watts/ft)[0.001 kw/watt] (1 yr)[365 day/yr][24hr/day][3413 BTU/kw·hr] (330 ft)=1.9733×10⁹ BTU/pattern/year.

Steam heating for one well pattern for one year is given by:

Q _(s) =q _(s) ·t·h _(s)(BTU/pattern/year);  (EQN. 13)

with Q_(s)=(500 bbls/day)(1 yr) [365 day/yr][1000 BTU/1b][350lbs/bbl]=63.875×10⁹ BTU/pattern/year.

Thus, electric heat divided by total heat is given by:

Q _(E)/(Q _(E) +Q _(s))×100=3% of the total heat.  (EQN. 14)

Thus, the electrical energy is only a small fraction of the total heatinjected into the formation.

The actual temperature of the region around a heater is described by anexponential integral function. The integrated form of the exponentialintegral function shows that about half the energy injected is nearlyequal to about half of the injection well temperature. The temperaturerequired to reduce viscosity of the heavy oil is assumed to be 500° F.The volume heated to 500° F. by an electric heater in one year is giveby:

V _(E)=πr².  (EQN. 15)

The heat balance is given by:

Q _(E)=(π_(E) ²)(s)(ρc)(ΔT).  (EQN. 16)

Thus, r_(E) can be solved for and is found to be 10.4 ft. For anelectric heater operated at 1000° F., the diameter of a cylinder heatedto half that temperature for one year would be about 23 ft. Depending onthe permeability profile in the injection wells, additional horizontalwells may be stacked above the one at the bottom of the formation and/orperiods of electric heating may be extended. For a ten year heatingperiod, the diameter of the region heated above 500° F. would be about60 ft.

If all the steam were injected uniformly into the steam injectors overthe 100 ft. interval for a period of one year, the equivalent volume offormation that could be heated to 500° F. would be give by:

Q _(s)=(πr _(s) ²)(s)(ρc)(ΔT).  (EQN. 17)

Solve for r_(s) give an r_(s) of 107 ft. This amount of heat would besufficient to heat about ¾ of the pattern to 500° F.

Nanofiltration Example

A liquid sample (500 mL, 398.68 grams) was obtained from an in situ heattreatment process. The liquid sample contained 0.0069 grams of sulfurand 0.0118 grams of nitrogen per gram of liquid sample. The finalboiling point of the liquid sample was 481° C. and the liquid sample hada density of 0.8474. The membrane separation unit used to filter thesample was a laboratory flat sheet membrane installation type P28 asobtained from CM Celfa Membrantechnik A. G. (Switzerland). A single2-micron thick poly di-methyl siloxane membrane (GKSS ForschungszentrumGmbH, Geesthact, Germany) was used as the filtration medium. Thefiltration system was operated at 50° C. and a pressure difference overthe membrane was 10 bar. The pressure at the permeate side was nearlyatmospheric. The permeate was collected and recycled through thefiltration system to simulate a continuous process. The permeate wasblanketed with nitrogen to prevent contact with ambient air. Theretentate was also collected for analysis. During filtration the averageflux of 2 kg/m2/bar/hr did not measurably decline from an initial fluxduring the filtration. The filtered liquid (298.15 grams, 74.7%recovery) contained 0.007 grams of sulfur and 0.0124 grams of nitrogenper gram of filtered liquid; and the filtered liquid had a density of0.8459 and a final boiling point of 486° C. The retentate (56.46 grams,14.16% recovery) contained 0.0076 grams of sulfur and 0.0158 grams ofnitrogen per gram of retentate; and the retentate had a density of0.8714 and a final boiling point of 543° C.

Fouling Testing Example

The unfiltered and filtered liquid samples from the previous Examplewere tested for fouling behavior. Fouling behavior was determined usingan Alcor thermal fouling tester. The Alcor thermal fouling tester is aminiature shell and tube heat exchanger made of 1018 steel which wasgrated with Norton R222 sandpaper before use. During the test the sampleoutlet temperature, (T_(out)) was monitored while the heat-exchangertemperature (T_(c)) was kept at a constant value. If fouling occurs andmaterial is deposited on the tube surface, the heat resistance of thesample increases and consequently the outlet temperature decreases.Hence the decrease in outlet temperature after a given period of time isa measure of fouling severity. The temperature decrease after two hoursof operation is used as fouling severity indicator.ΔT=T_(out(o))−T_(out(2h)). T_(out(o)) is defined as the maximum (stable)outlet temperature obtained at the start of the test, T_(out(2h)) isrecorded 2 hours after the first noted decrease of the outlettemperature or when the outlet temperature has been stable for at least2 hours.

During each test, the liquid sample was continuously circulated throughthe heat exchanger at approximately 3 mL/min. The residence time in theheat exchanger was about 10 seconds. The operating conditions were asfollows: 40 bar of pressure, T_(sample) was about 50° C., Tc was 350°C., test time was 4.41 hours. The ΔT for the unfiltered liquid streamsample was 15° C. The ΔT for the filtered sample was zero.

This example demonstrates that nanofiltration of a liquid streamproduced from an in situ heat treatment process removes at least aportion of clogging compositions.

Olefin Production Example

An experimental pilot system was used to conduct the experiments. Thepilot system included a feed supply system, a catalyst loading andtransfer system, a fast fluidized riser reactor, a stripper, a productseparation and collecting system, and a regenerator. The riser reactorwas an adiabatic riser having an inner diameter of from 11 mm to 19 mmand a length of about 3.2 m. The riser reactor outlet was in fluidcommunication with the stripper that was operated at the sametemperature as the riser reactor outlet flow and in a manner to provideessentially 100 percent stripping efficiency. The regenerator was amulti-stage continuous regenerator used for regenerating the spentcatalyst. The spent catalyst was fed to the regenerator at a controlledrate and the regenerated catalyst was collected in a vessel. Materialbalances were obtained during each of the experimental runs at 30-minuteintervals. Composite gas samples were analyzed by use of an on-line gaschromatograph and the liquid product samples were collected and analyzedovernight. The coke yield was measured by measuring the catalyst flowand by measuring the delta coke on the catalyst as determined bymeasuring the coke on the spent and regenerated catalyst samples takenfor each run when the unit was operating at steady state.

A liquid stream produced from an in situ heat treatment process wasfractioned to obtain a vacuum gas oil (VGO) stream having a boilingrange distribution from 310° C. to 640° C. The VGO stream was contactedwith a fluidized catalytic cracker E-Cat containing 10% ZSM-5 additivein the catalytic system described above. The riser reactor temperaturewas maintained at 593° C. (1100° F.). The product produced contained,per gram of product, 0.1402 grams of C3 olefins, 0.137 grams of C4olefins, 0.0897 grams of C5 olefins, 0.0152 grams of iso-C5 olefins,0.0505 grams isobutylene, 0.0159 grams of ethane, 0.0249 grams ofisobutane, 0.0089 grams of n-butane, 0.0043 grams pentane, 0.0209 gramsiso-pentane, 0.2728 grams of a mixture of C6 hydrocarbons andhydrocarbons having a boiling point of at most 232° C. (450° F.), 0.0881grams of hydrocarbons having a boiling range distribution between 232°C. and 343° C. (between 450° F. and 650° F.), 0.0769 grams ofhydrocarbons having a boiling range distribution between 343° C. and399° C. (650° F. and 750° F.) and 0.0386 grams of hydrocarbons having aboiling range distribution of at least 399° C. (750° F.) and 0.0323grams of coke.

This example demonstrates a method of producing crude product byfractionating liquid stream produced from separation of the liquidstream from the formation fluid to produce a crude product having aboiling point above 343° C.; and catalytically cracking the crudeproduct having the boiling point above 343° C. to produce one or moreadditional crude products, wherein least one of the additional crudeproducts is a second gas stream.

Production of Olefins from a Liquid Stream Example

A thermally cracked naphtha was used to simulate a liquid streamproduced from an in situ heat treatment process having a boiling rangedistribution from 30° C. to 182° C. The naphtha contained, per gram ofnaphtha, 0.186 grams of naphthenes, 0.238 grams of isoparaffins, 0.328grams of n-paraffins, 0.029 grams cyclo-olefins, 0.046 grams ofiso-olefins, 0.064 grams of n-olefins and 0.109 grams of aromatics. Thenaphtha stream was contacted with a FCC E-Cat with 10% ZSM-5 additive inthe catalytically cracking system described above to produce a crudeproduct. The riser reactor temperature was maintained at 593° C. (1100°F.). The crude product included, per gram of crude product, 0.1308 gramsethylene, 0.0139 grams of ethane, 0.0966 grams C4-olefins, 0.0343 gramsC4 iso-olefins, 0.0175 grams butane, 0.0299 grams isobutane, 0.0525grams C5 olefins, 0.0309 grams C5 iso-olefins, 0.0442 grams pentane,0.0384 grams iso-pentane, 0.4943 grams of a mixture of C6 hydrocarbonsand hydrocarbons having a boiling point of at most 232° C. (450° F.),0.0201 grams of hydrocarbons having a boiling range distribution between232° C. and 343° C. (between 450° F. and 650° F.), 0.0029 grams ofhydrocarbons having a boiling range distribution between 343° C. and399° C. (650° F. and 750° F.) and 0.00128 grams of hydrocarbons having aboiling range distribution of at least 399° C. (750° F.) and 0.00128grams of coke. The total amount of C₃-C₅ olefins was 0.2799 grams pergram of naphtha.

This example demonstrates a method of producing crude product byfractionating liquid stream produced from separation of the liquidstream from the formation fluid to produce a crude product having aboiling point above 343° C.; and catalytically cracking the crudeproduct having the boiling point above 343° C. to produce one or moreadditional crude products, wherein least one of the additional crudeproducts is a second gas stream.

In this patent, certain U.S. patents, U.S. patent applications, andother materials (for example, articles) have been incorporated byreference. The text of such U.S. patents, U.S. patent applications, andother materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

Further modifications and alternative embodiments of various aspects ofthe invention may be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as the presently preferred embodiments. Elements andmaterials may be substituted for those illustrated and described herein,parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims. In addition, it is to be understood that featuresdescribed herein independently may, in certain embodiments, be combined.

1-1140. (canceled)
 1141. A composition, comprising: from about 18percent to about 22 percent by weight chromium; from about 5 percent toabout 13 percent by weight nickel; between about percent and about 10percent by weight copper; from 3 percent to about 10 percent by weightmanganese; from about 0.5 percent to about 1.5 percent by weightniobium; and from about 38 percent to about 63 percent by weight iron.1142. The composition of claim 1141, wherein the composition has a yieldstrength of greater than 35 ksi at about 800° C.
 1143. The compositionof claim 1141, wherein the composition, after being annealed, has ayield strength at about 800° C. that changes less than 20 percent as aresult of being cold worked by twenty percent.
 1144. The composition ofclaim 1141, further comprising from at least 0.12 percent to about 0.5percent by weight nitrogen.
 1145. The composition of claim 1141, furthercomprising about 0.3 percent to about 1 percent by weight molybdenum.1146. The composition of claim 1141, further comprising from about 0.08percent to about 0.2 percent by weight carbon.
 1147. The composition ofclaim 1141, further comprising from at least 0.12 percent to about 0.5percent by weight nitrogen, and nanonitride precipitates.
 1148. Thecomposition of claim 1147, wherein the nanonitride precipitates comprisea majority of particles having maximum dimensions in the range of fiveto one hundred nanometers.
 1149. The composition of claim 1147, furthercomprising from about 0.08 percent to about 0.2 percent by weight carbonand nanocarbide precipitates.
 1150. The composition of claim 1149,wherein the nanocarbide precipitates comprise particles having maximumdimensions in the range of five to two hundred nanometers.
 1151. Thecomposition of claim 1141, wherein the composition, when at about 800°C., has at least 3.25 percent by weight of precipitates.
 1152. Thecomposition of claim 1141, further comprising from at least 0.12 percentto about 0.5 percent by weight nitrogen and from about 0.08 percent toabout 0.2 percent by weight carbon, wherein the composition, when atabout 800° C., has at least two percent by weight of precipitatescomprising phases selected from the group consisting of Cu, M(C,N),M₂(C,N) or M₂₃C₆ phases, where M is nickel, copper, niobium, iron ormanganese.
 1153. The composition of claim 1141, further comprising fromat least 0.12 percent to about 0.5 percent by weight nitrogen and fromabout 0.08 percent to about 0.2 percent by weight carbon, wherein thecomposition has been annealed at an annealing temperature, and thecomposition comprises at least 1.5 percent by weight of more phasesselected from the group consisting of Cu, M(C,N), M₂(C,N) or M₂₃C₆phases, where M is nickel, copper, niobium, iron or manganese, at 800°C. than the composition comprising phases selected from the groupconsisting of Cu, M(C,N), M₂(C,N) or M₂₃C₆ phases, where M is nickel,copper, niobium, iron or manganese, at the annealing temperature. 1154.The composition of claim 1153, wherein the annealing temperature is atleast 1250° C.
 1155. The composition of claim 1153, wherein theannealing temperature is at between about 1300° C. and the meltingtemperature of the composition.
 1156. The composition of claim 1141,wherein the composition, when at about 800° C., has at least 4 percentby weight of precipitates.
 1157. The composition of claim 1141, whereinthe composition, when at about 800° C., has at least 8 percent by weightof precipitates.
 1158. A composition comprising: from about 18 percentto about 22 percent by weight chromium; from about 5 percent to about 14percent by weight nickel; from about 1 percent to about 10 percent byweight copper; from about 0.5 percent to about 1.5 percent by weightniobium; from 13 percent to about 10 percent by weight manganese; fromabout 0.5 percent to about 1.5 percent by weight of tungsten; from about36 percent to about 74 percent by weight iron; and wherein the ratio oftungsten to copper is between about 1/10 and 10/1.
 1159. The compositionof claim 1158, wherein the ratio of copper to manganese is between about1/5 and 5/1.
 1160. The composition of claim 1158, further comprisingfrom at least 0.12 percent to about 0.5 percent by weight nitrogen, andprecipitates of nanonitrides, wherein the nanonitride precipitatescomprise a majority of particles having a maximum dimension of betweenfive and one hundred nanometers.
 1161. The composition of claim 1160,wherein the composition, when at about 800° C., has at least 3.25percent by weight of nanonitride precipitates.
 1162. The composition ofclaim 1160, wherein the composition, when at about 800° C., has at least4 percent by weight of nanonitride precipitates.
 1163. The compositionof claim 1158, further comprising from at least 0.12 percent to about0.5 percent by weight nitrogen and from about 0.08 percent to about 0.2percent by weight carbon, wherein the composition, when at about 800°C., has at least two percent by weight of precipitates comprising phasesselected from the group consisting of Cu, M(C,N), M₂(C,N) or M₂₃C₆phases, where M is nickel, copper, niobium, iron or manganese.
 1164. Thecomposition of claim 1158, wherein the composition has been subjected tocold work to an extent of at least about 10 percent.
 1165. Thecomposition of claim 1158, wherein the composition has been subjected tohot work to an extent of at least about ten percent.
 1166. Thecomposition of claim 1158, wherein the composition has been subjected tohot aging. 1167-1181. (canceled)
 1182. A composition, comprising: from18 percent to 22 percent by weight chromium; from 11 percent to 14percent by weight nickel; less than about 3 percent by weight copper;from 3 percent to 10 percent by weight manganese; from 0.5 percent to1.5 percent by weight niobium; and wherein the material is capable ofbeing cold-worked to form a wrought material.
 1183. The composition ofclaim 1182, wherein the material is capable of being hot-worked. 1184.The composition of claim 1182, further comprising from 0.07 percent to0.15 percent by weight carbon.
 1185. The composition of claim 1182,further comprising from 0.2 percent to 0.5 percent by weight nitrogen.1186. The composition of claim 1182, further comprising iron. 1187-1651.(canceled)
 1652. The composition of claim 1141, further comprising fromabout 0.3 percent to about 1 percent by weight silicon.
 1653. Thecomposition of claim 1141, further comprising from about 0.5 percent toabout 2 percent by weight tungsten.
 1654. The composition of claim 1182,further comprising less than about 0.75 percent by weight silicon. 1655.The composition of claim 1182, further comprising from about 0.5 percentto about 1.5 percent by weight tungsten.